[Federal Register Volume 79, Number 117 (Wednesday, June 18, 2014)]
[Proposed Rules]
[Pages 34829-34958]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-13726]
[[Page 34829]]
Vol. 79
Wednesday,
No. 117
June 18, 2014
Part II
Environmental Protection Agency
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40 CFR Part 60
Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units; Proposed Rule
Federal Register / Vol. 79 , No. 117 / Wednesday, June 18, 2014 /
Proposed Rules
[[Page 34830]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2013-0602; FRL-9911-86-OAR]
RIN 2060-AR33
Carbon Pollution Emission Guidelines for Existing Stationary
Sources: Electric Utility Generating Units
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: In this action, the Environmental Protection Agency (EPA) is
proposing emission guidelines for states to follow in developing plans
to address greenhouse gas emissions from existing fossil fuel-fired
electric generating units. Specifically, the EPA is proposing state-
specific rate-based goals for carbon dioxide emissions from the power
sector, as well as guidelines for states to follow in developing plans
to achieve the state-specific goals. This rule, as proposed, would
continue progress already underway to reduce carbon dioxide emissions
from existing fossil fuel-fired power plants in the United States.
DATES: Comments on the proposed rule. Comments must be received on or
before October 16, 2014. Comments on the information collection
request. Under the Paperwork Reduction Act (PRA), since the Office of
Management and Budget (OMB) is required to make a decision concerning
the information collection request between 30 and 60 days after June
18, 2014, a comment to the OMB is best assured of having its full
effect if the OMB receives it by July 18, 2014.
Public Hearing. Four public hearings will be convened. On July 29,
2014, one public hearing will be held in Atlanta, Georgia, at the Sam
Nunn Atlanta Federal Center Main Tower Bridge Conference Area,
Conference Room B, 61 Forsyth Street SW., Atlanta, GA 30303, and one
will be held in Denver, Colorado, at the EPA's Region 8 Building, 1595
Wynkoop Street, Denver, Colorado 80202. On July 30, 2014, a public
hearing will be held in Washington, DC, at the William Jefferson
Clinton East Building, Room 1152, 1201 Constitution Avenue NW.,
Washington, DC 20004. On July 31, 2014, a public hearing will be held
in Pittsburgh, Pennsylvania at the William S. Moorhead Federal
Building, Room 1310, 1000 Liberty Avenue, Pittsburgh, Pennsylvania
15222. The hearings in Pittsburgh, Pennsylvania, Atlanta, Georgia, and
Washington, DC, will convene at 9:00 a.m. and end at 8:00 p.m. (Eastern
Standard Time). The hearing in Denver, Colorado, will convene at 9:00
a.m. and end at 8:00 p.m. (Mountain Daylight Time). For all hearings
there will be a lunch break from 12:00 p.m. to 1:00 p.m. and a dinner
break from 5:00 p.m. to 6:00 p.m. Please contact Ms. Pamela Garrett at
919-541-7966 or at garrett.pamela@epa.gov to register to speak at one
of the hearings. The last day to pre-register in advance to speak at
the hearings will be Friday, July 25, 2014. Additionally, requests to
speak will be taken the day of the hearings at the hearing registration
desk, although preferences on speaking times may not be able to be
fulfilled. If you require the service of a translator or special
accommodations such as audio description, please let us know at the
time of registration.
The hearings will provide interested parties the opportunity to
present data, views or arguments concerning the proposed action. The
EPA will make every effort to accommodate all speakers who arrive and
register. Because these hearings are being held at U.S. government
facilities, individuals planning to attend the hearing should be
prepared to show valid picture identification to the security staff in
order to gain access to the meeting room. Please note that the REAL ID
Act, passed by Congress in 2005, established new requirements for
entering federal facilities. These requirements will take effect July
21, 2014. If your driver's license is issued by Alaska, American Samoa,
Arizona, Kentucky, Louisiana, Maine, Massachusetts, Minnesota, Montana,
New York, Oklahoma, or the state of Washington, you must present an
additional form of identification to enter the federal buildings where
the public hearings will be held. Acceptable alternative forms of
identification include: Federal employee badges, passports, enhanced
driver's licenses and military identification cards. We will list any
additional acceptable forms of identification at: http://www2.epa.gov/cleanpowerplan/. In addition, you will need to obtain a property pass
for any personal belongings you bring with you. Upon leaving the
building, you will be required to return this property pass to the
security desk. No large signs will be allowed in the building, cameras
may only be used outside of the building and demonstrations will not be
allowed on federal property for security reasons.
The EPA may ask clarifying questions during the oral presentations,
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral comments and
supporting information presented at the public hearing. Commenters
should notify Ms. Garrett if they will need specific equipment, or if
there are other special needs related to providing comments at the
hearings. Verbatim transcripts of the hearings and written statements
will be included in the docket for the rulemaking. The EPA will make
every effort to follow the schedule as closely as possible on the day
of the hearing; however, please plan for the hearings to run either
ahead of schedule or behind schedule. Additionally, more information
regarding the hearings will be available at: http://www2.epa.gov/cleanpowerplan/.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2013-0602, by one of the following methods:
Federal eRulemaking portal: http://www.regulations.gov. Follow the
online instructions for submitting comments.
Email: A-and-R-Docket@epa.gov. Include docket ID No. EPA-HQ-OAR-
2013-0602 in the subject line of the message.
Facsimile: (202) 566-9744. Include docket ID No. EPA-HQ-OAR-2013-
0602 on the cover page.
Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC),
Mail code 28221T, Attn: Docket ID No. EPA-HQ-OAR-2013-0602, 1200
Pennsylvania Ave. NW., Washington, DC 20460. In addition, please mail a
copy of your comments on the information collection provisions to the
Office of Information and Regulatory Affairs, OMB, Attn: Desk Officer
for the EPA, 725 17th St. NW., Washington, DC 20503.
Hand/Courier Delivery: EPA Docket Center, Room 3334, EPA WJC West
Building, 1301 Constitution Ave. NW., Washington, DC 20004, Attn:
Docket ID No. EPA-HQ-OAR-2013-0602. Such deliveries are accepted only
during the Docket Center's normal hours of operation (8:30 a.m. to 4:30
p.m., Monday through Friday, excluding federal holidays), and special
arrangements should be made for deliveries of boxed information.
Instructions: All submissions must include the agency name and
docket ID number (EPA-HQ-OAR-2013-0602). The EPA's policy is to include
all comments received without change, including any personal
information provided, in the public docket, available online at http://www.regulations.gov, unless the comment includes information claimed to
be Confidential
[[Page 34831]]
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through http://www.regulations.gov or
email. Send or deliver information identified as CBI only to the
following address: Mr. Roberto Morales, OAQPS Document Control Officer
(C404-02), Office of Air Quality Planning and Standards, U.S. EPA,
Research Triangle Park, North Carolina 27711, Attention Docket ID No.
EPA-HQ-OAR-2013-0602. Clearly mark the part or all of the information
that you claim to be CBI. For CBI information on a disk or CD-ROM that
you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and
then identify electronically within the disk or CD-ROM the specific
information you claim as CBI. In addition to one complete version of
the comment that includes information claimed as CBI, you must submit a
copy of the comment that does not contain the information claimed as
CBI for inclusion in the public docket. Information so marked will not
be disclosed except in accordance with procedures set forth in 40 CFR
Part 2.
The EPA requests that you also submit a separate copy of your
comments to the contact person identified below (see FOR FURTHER
INFORMATION CONTACT). If the comment includes information you consider
to be CBI or otherwise protected, you should send a copy of the comment
that does not contain the information claimed as CBI or otherwise
protected.
The www.regulations.gov Web site is an ``anonymous access'' system,
which means the EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption and be free of any
defects or viruses.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available (e.g., CBI or other information
whose disclosure is restricted by statute). Certain other material,
such as copyrighted material, will be publicly available only in hard
copy. Publicly available docket materials are available either
electronically in http://www.regulations.gov or in hard copy at the EPA
Docket Center, William Jefferson Clinton Building West, Room 3334, 1301
Constitution Ave. NW., Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Air Docket is (202) 566-
1742. Visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm for additional information about the EPA's public
docket.
In addition to being available in the docket, an electronic copy of
this proposed rule will be available on the Worldwide Web (WWW).
Following signature, a copy of this proposed rule will be posted at the
following address: http://www2.epa.gov/cleanpowerplan/.
FOR FURTHER INFORMATION CONTACT: Ms. Amy Vasu, Sector Policies and
Programs Division (D205-01), U.S. EPA, Research Triangle Park, NC
27711; telephone number (919) 541-0107, facsimile number (919) 541-
4991; email address: vasu.amy@epa.gov or Ms. Marguerite McLamb, Sector
Policies and Programs Division (D205-01), U.S. EPA, Research Triangle
Park, NC 27711; telephone number (919) 541-7858, facsimile number (919)
541-4991; email address: mclamb.marguerite@epa.gov.
SUPPLEMENTARY INFORMATION:
Acronyms. A number of acronyms and chemical symbols are used in
this preamble. While this may not be an exhaustive list, to ease the
reading of this preamble and for reference purposes, the following
terms and acronyms are defined as follows:
ACEEE American Council for an Energy Efficient Economy
AEO Annual Energy Outlook
AFL-CIO American Federation of Labor and Congress of Industrial
Organizations
ASTM American Society for Testing of Materials
BSER Best System of Emission Reduction
Btu/kWh British Thermal Units per Kilowatt-hour
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CEMS Continuous Emissions Monitoring System
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE Department of Energy
ECMPS Emissions Collection and Monitoring Plan System
EERS Energy Efficiency Resource Standard
EGU Electric Generating Unit
EIA Energy Information Administration
EM&V Evaluation, Measurement and Verification
EO Executive Order
EPA Environmental Protection Agency
FR Federal Register
GHG Greenhouse Gas
GW Gigawatt
HAP Hazardous Air Pollutant
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
IRP Integrated Resource Plan
ISO Independent System Operator
kW Kilowatt
kWh Kilowatt-hour
lb CO2/MWh Pounds of CO2 per Megawatt-hour
LBNL Lawrence Berkeley National Laboratory
MMBtu Million British Thermal Units
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System Commissioners
NAS National Academy of Sciences
NGCC Natural Gas Combined Cycle
NOX Nitrogen Oxides
NRC National Research Council
NSPS New Source Performance Standard
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
NYSERDA New York State Energy Research and Development Authority
OMB Office of Management and Budget
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSB Public Service Board
PUC Public Utilities Commission
REC Renewable Energy Credit
RES Renewable Energy Standard
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
RTO Regional Transmission Operator
SBA Small Business Administration
SBC System Benefits Charge
SCC Social Cost of Carbon
SIP State Implementation Plan
SO2 Sulfur Dioxide
Tg Teragram (one trillion (10 \12\) grams)
TSD Technical Support Document
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard
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Organization of This Document. The information presented in this
preamble is organized as follows:
I. General Information
A. Executive Summary
B. Organization and Approach for This Proposed Rule
II. Background
A. Climate Change Impacts From GHG Emissions
B. GHG Emissions From Fossil Fuel-Fired EGUs
C. The Utility Power Sector
D. Statutory and Regulatory Requirements
III. Stakeholder Outreach and Conclusions
A. Stakeholder Outreach
B. Key Messages From Stakeholders
C. Key Stakeholder Proposals
D. Consideration of the Existing Range of Policies and Programs
E. Conclusions
IV. Rule Requirements and Legal Basis
A. Summary of Rule Requirements
B. Summary of Legal Basis
V. Authority To Regulate Carbon Dioxide and EGUs, Affected Sources,
and Treatment of Categories
A. Authority To Regulate Carbon Dioxide
B. Authority To Regulate EGUs
C. Affected Sources
D. Implications for Tribes and U.S. Territories
E. Combined Categories and Codification in the Code of Federal
Regulations
VI. Building Blocks for Setting State Goals and the Best System of
Emission Reduction
A. Introduction
B. Building Blocks for Setting State Goals
C. Detailed Discussion of Building Blocks and Other Options
Considered
D. Potential Combinations of the Building Blocks as Components
of the Best System of Emission Reduction
E. Determination of the Best System of Emission Reduction
VII. State Goals
A. Overview
B. Form of Goals
C. Proposed Goals and Computation Procedure
D. State Flexibilities
E. Alternate Goals and Other Approaches Considered
F. Reliable Affordable Electricity
VIII. State Plans
A. Overview
B. Approach
C. Criteria for Approving State Plans
D. State Plan Components
E. Process for State Plan Submittal and Review
F. State Plan Considerations
G. Additional Factors That Can Help States Meet Their
CO2 Emission Performance Goals
H. Resources for States To Consider in Developing Plans
IX. Implications for Other EPA Programs and Rules
A. Implications for NSR Program
B. Implications for Title V Program
C. Interactions With Other EPA Rules
X. Impacts of the Proposed Action
A. What are the air impacts?
B. Comparison of Building Block Approaches
C. Endangered Species Act
D. What are the energy impacts?
E. What are the compliance costs?
F. What are the economic and employment impacts?
G. What are the benefits of the proposed action?
XI. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review, and
Executive Order 13563, Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act of 1995
E. Executive Order 13132, Federalism
F. Executive Order 13175, Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045, Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898, Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
XII. Statutory Authority
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
Under the authority of Clean Air Act (CAA) section 111(d), the EPA
is proposing emission guidelines for states to follow in developing
plans to address greenhouse gas (GHG) emissions from existing fossil
fuel-fired electric generating units (EGUs). In this summary, we
outline the proposal; discuss its purpose; summarize its major
provisions, including the EPA's approach to determining goals; describe
the broad range of options available to states, including flexibility
in timing requirements both for plan submission and compliance
deadlines under those plans; and briefly describe the estimated
CO2 emission reductions, costs and benefits expected to
result from full implementation of the proposal.
This rule, as proposed, would continue progress already underway to
lower the carbon intensity of power generation in the United States
(U.S.). Lower carbon intensity means fewer emissions of CO2,
a potent greenhouse gas that contributes to climate change. This
proposal is a significant step forward in the EPA and states partnering
to reduce GHG emissions in the U.S. The proposal incorporates critical
elements that reflect the information and views shared during the
unprecedented effort that the EPA has undertaken, beginning in the
summer of 2013, to interact directly with, and solicit input from, a
wide range of states and stakeholders. This effort encompassed several
hundred meetings across the country with state environmental and energy
officials, public utility commissioners, system operators, utilities
and public interest advocates, as well as members of the public. Many
participants submitted written material and data to the EPA as well.
Nationwide, by 2030, this rule would achieve CO2
emission reductions from the power sector of approximately 30 percent
from CO2 emission levels in 2005. This goal is achievable
because innovations in the production, distribution and use of
electricity are already making the power sector more efficient and
sustainable while maintaining an affordable, reliable and diverse
energy mix. This proposed rule would reinforce and continue this
progress. The EPA projects that, in 2030, the significant reductions in
the harmful carbon pollution and in other air pollution, to which this
rule would lead, would result in net climate and health benefits of $48
billion to $82 billion. At the same time, coal and natural gas would
remain the two leading sources of electricity generation in the U.S.,
with each providing more than 30 percent of the projected generation.
Based on evidence from programs already being implemented by many
states as well as input received from stakeholders, the agency
recognizes that the most cost-effective system of emission reduction
for GHG emissions from the power sector under CAA section 111(d)
entails not only improving the efficiency of fossil fuel-fired EGUs,
but also addressing their utilization by taking advantage of
opportunities for lower-emitting generation and reduced electricity
demand across the electricity system's interconnecting network or grid.
The proposed guidelines are based on and would reinforce the
actions already being taken by states and utilities to upgrade aging
electricity infrastructure with 21st century technologies. The
guidelines would ensure that these trends continue in ways that are
consistent with the long-term planning and investment processes already
used in this sector, to meet both region- and state-specific needs. The
proposal provides flexibility for states to build upon their progress,
and the progress of cities and towns, in addressing GHGs. It also
allows states to pursue policies to reduce carbon pollution that: (1)
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Continue to rely on a diverse set of energy resources, (2) ensure
electric system reliability, (3) provide affordable electricity, (4)
recognize investments that states and power companies are already
making, and (5) can be tailored to meet the specific energy,
environmental and economic needs and goals of each state. Thus, the
proposed guidelines would achieve meaningful CO2 emission
reduction while maintaining the reliability and affordability of
electricity in the U.S.
a. Proposal Elements
The proposal has two main elements: (1) State-specific emission
rate-based CO2 goals and (2) guidelines for the development,
submission and implementation of state plans. To set the state-specific
CO2 goals, the EPA analyzed the practical and affordable
strategies that states and utilities are already using to lower carbon
pollution from the power sector. These strategies include improvements
in efficiency at carbon-intensive power plants, programs that enhance
the dispatch priority of, and spur private investments in, low emitting
and renewable power sources, as well as programs that help homes and
businesses use electricity more efficiently. In addition, in
calculating each state's CO2 goal, the EPA took into
consideration the state's fuel mix, its electricity market and numerous
other factors. Thus, each state's goal reflects its unique conditions.
While this proposal lays out state-specific CO2 goals
that each state is required to meet, it does not prescribe how a state
should meet its goal. CAA section 111(d) creates a partnership between
the EPA and the states under which the EPA sets these goals and the
states take the lead on meeting them by creating plans that are
consistent with the EPA guidelines. Each state will have the
flexibility to design a program to meet its goal in a manner that
reflects its particular circumstances and energy and environmental
policy objectives. Each state can do so alone or can collaborate with
other states on multi-state plans that may provide additional
opportunities for cost savings and flexibility.
To facilitate the state planning process, this proposal lays out
guidelines for the development and implementation of state plans. The
proposal describes the components of a state plan, the latitude states
have in developing compliance strategies, the flexibility they have in
the timing for submittal of their plans and the flexibility they have
in determining the schedule by which their sources must achieve the
required CO2 reductions. The EPA recognizes that each state
has differing policy considerations--including varying emission
reduction opportunities and existing state programs and measures--and
that the characteristics of the electricity system in each state (e.g.,
utility regulatory structure, generation mix and electricity demand)
also differ. Therefore, the proposed guidelines provide states with
options for meeting the state-specific goals established by the EPA in
a manner that accommodates a diverse range of state approaches. This
proposal also gives states considerable flexibility with respect to the
timeframes for plan development and implementation, providing up to two
or three years for submission of final plans and providing up to
fifteen years for full implementation of all emission reduction
measures, after the proposal is finalized.
Addressing a concern raised by both utilities and states, the EPA
is proposing that states could choose approaches in their compliance
plans under which full responsibility for actions achieving reductions
is not placed entirely upon emitting EGUs; instead, state plans could
include measures and policies (e.g., demand-side energy efficiency
programs and renewable portfolio standards) for which the state itself
is responsible. Of course, individual states would also have the option
of structuring programs (e.g., allowance-trading programs) under which
full responsibility rests on the affected EGUs.
The EPA believes that, using the flexibilities inherent in CAA
section 111(d), this proposal would result in significant reductions of
GHG emissions that cause harmful climate change, while providing states
with ample opportunity to design plans that use innovative, cost-
effective strategies that take advantage of investments already being
made in programs and measures that lower the carbon intensity of the
power sector and reduce GHG emissions.
b. Policy Context and Industry Conditions
This proposal is an important step toward achieving the GHG
emission reductions needed to address the serious threat of climate
change. GHG pollution threatens the American public by leading to
potentially rapid, damaging and long-lasting changes in our climate
that can have a range of severe negative effects on human health and
the environment. CO2 is the primary GHG pollutant,
accounting for nearly three-quarters of global GHG emissions \1\ and 82
percent of U.S. GHG emissions.\2\ The May 2014 report of the National
Climate Assessment \3\ concluded that climate change impacts are
already manifesting themselves and imposing losses and costs. The
report documents increases in extreme weather and climate events in
recent decades, damage and disruption to infrastructure and
agriculture, and projects continued increases in impacts across a wide
range of communities, sectors, and ecosystems.
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\1\ Intergovernmental Panel on Climate Change (IPCC) report,
``Contribution of Working Group I to the Fourth Assessment Report of
the Intergovernmental Panel on Climate Change,'' 2007. Available at
http://epa.gov/climatechange/ghgemissions/global.html.
\2\ Table ES-2 ``Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990-2012'', Report EPA 430-R-14-003, United States
Environmental Protection Agency, April 15, 2014.
\3\ U.S. Global Change Research Program, Climate Change Impacts
in the United States: The Third National Climate Assessment, May
2014. Available at http://nca2014.globalchange.gov/.
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The President's Climate Action Plan,\4\ issued in June 2013,
recognizes that climate change has far-reaching harmful consequences
and real economic costs. The Climate Action Plan details a broad array
of actions to reduce GHG emissions that contribute to climate change
and affect public health and the environment. One of the plan's goals
is to reduce CO2 emissions from power plants. This is
because fossil fuel-fired EGUs are, by far, the largest emitters of
GHGs, primarily in the form of CO2, among stationary sources
in the U.S. To accomplish this goal, President Obama issued a
Presidential Memorandum \5\ that recognized the importance of
significant and prompt action. The Memorandum directed the EPA to
complete carbon pollution standards, regulations or guidelines, as
appropriate, for modified, reconstructed and existing power plants by
June 1, 2015, and in doing so to build on state leadership in moving
toward a cleaner power sector.
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\4\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
\5\ Presidential Memorandum--Power Sector Carbon Pollution
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
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The way that power is produced, distributed and used is already
changing due to advancements in innovative power sector technologies
and in the availability and cost of low carbon fuel, renewable energy
and energy efficient demand-side technologies, as well as economic
conditions. In addition, the average age of the coal-fired generating
fleet is increasing. In 2025, the average age of the coal-fired
generating fleet is
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projected to be 49 years old, and 20 percent of units would be more
than 60 years old if they remained in operation at that time.
Therefore, even in the absence of additional environmental regulation,
states and utilities can be expected to be, and already are, making
plans to address the changes necessitated by the aging of current
assets and infrastructure. With change inevitably underway between now
and 2030, a CAA section 111(d) rulemaking for CO2 emissions
is timely and can inform current and ongoing decision making by states
and utilities, as well as private sector business and technology
investments. As states develop their plans, they will make key
decisions that will stimulate private sector investment and innovation
associated with reducing GHG emissions. We expect that many states will
consider the opportunities offered for their respective economies as a
result of this investment.
The proposed guidelines are designed to build on and reinforce
progress by states, cities and towns, and companies on a growing
variety of sustainable strategies to reduce power sector CO2
emissions. At the same time, the EPA believes that this proposal
provides flexibility for states to develop plans that align with their
unique circumstances, as well as their other environmental policy,
energy and economic goals. All states will have the opportunity to
shape their plans as they believe appropriate for meeting the proposed
CO2 goals. This includes states with long-established
reliance on coal-fired generation, as well as states with a commitment
to promoting renewable energy (including through sustainable forestry
initiatives). It also includes states that are already participating in
or implementing CO2 reduction programs, such as the Regional
Greenhouse Gas Initiative (RGGI), California's ``Global Warming
Solutions Act'' and Colorado's ``Clean Air, Clean Jobs Act''.
States would be able to rely on and extend programs they may
already have created to address the power sector. Those states
committed to Integrated Resource Planning (IRP) would be able to
establish their CO2 reduction plans within that framework,
while states with a more deregulated power sector system could develop
CO2 reduction plans within that specific framework. Each
state, including states without an existing program, would have the
opportunity to take advantage of a wide variety of strategies for
reducing CO2 emissions from affected EGUs. The EPA and other
federal entities, including the U.S. Department of Energy (DOE), the
Federal Energy Regulatory Commission (FERC) and the U.S. Department of
Agriculture, among others, are committed to sharing expertise with
interested states as they develop and implement their plans.
States would be able to address the economic interests of their
utilities and ratepayers by using the flexibilities in this proposed
action to: (1) Reduce costs to consumers, minimize stranded assets, and
spur private investments in renewable energy and energy efficiency
technologies and businesses; and (2) if they choose, work with other
states on multi-state approaches that reflect the regional structure of
electricity operating systems that exists in most parts of the country
and is critical to ensuring a reliable supply of affordable energy. The
proposed rule gives states the flexibility to provide a broad range of
compliance options that recognize that the power sector is made up of a
diverse range of companies that own and operate fossil fuel-fired EGUs,
including vertically integrated companies in regulated markets,
independent power producers, rural cooperatives and municipally-owned
utilities, all of which are likely to have different ranges of
opportunities to reduce GHG emissions while facing different challenges
in meeting these reductions.
Both existing state programs (such as RGGI, the California Global
Warming Solutions Act program and the Colorado Clean Air, Clean Jobs
Act program) and ideas suggested by stakeholders show that there are a
number of different ways that states can design programs that achieve
required reductions while working within existing market mechanisms
used to dispatch power effectively in the short term and to ensure
adequate capacity in the long term. These programs and programs for
conventional pollutants, such as the Acid Rain Program under Title IV
of the CAA, have demonstrated that compliance with environmental
programs can be monetized such that it is factored into power sector
economic decision making in ways that reduce the cost of controlling
pollution, maintain electricity system reliability and work within the
least cost dispatching principles that are key to operation of our
electric power grid. The proposal would also allow states to work
together with individual companies on potential specific challenges.
These and other flexibilities are discussed further in Section VIII of
the preamble.
a. CAA Section 111(d) Requirements
Under CAA section 111(d),\6\ state plans must establish standards
of performance that reflect the degree of emission limitation
achievable through the application of the ``best system of emission
reduction'' that, taking into account the cost of achieving such
reduction and any non-air quality health and environmental impacts and
energy requirements, the Administrator determines has been adequately
demonstrated (BSER).\7\ Consistent with CAA section 111(d), the EPA is
proposing state-specific goals that reflect the EPA's calculation of
the emission limitation that each state can achieve through the
application of the BSER. This calculation reflects the degree of
emission limitation that the state plan must achieve in order to
implement the BSER that the EPA has determined has been adequately
demonstrated and that, in turn, would be required to be, and via the
calculation, has been, applied for the affected EGUs in each state. A
CAA section 111(d) state plan will differ from a state implementation
plan (SIP) for a criteria air pollutant national ambient air quality
standard (NAAQS) in several respects, reflecting the significant
differences between CAA sections 110 and 111. A CAA section 110 SIP
must be designed to meet the NAAQS for a criteria air pollutant for a
particular area--not for a source category--within a timeframe
specified in the CAA. The NAAQS itself is based on the current body of
scientific evidence and, by law, does not reflect consideration of
cost. By contrast, a CAA section 111(d) state plan must be designed to
achieve a specific level of emission performance that has been
established for a particular source category within a timeframe
determined by the Administrator and, to some extent, by each state.
Moreover, the emission levels for the source category reflect a
determination of the BSER, which incorporates consideration of cost,
technical feasibility and other factors.
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\6\ See also 40 CFR 60.22(b)(5).
\7\ Under CAA section 111(a)(1) and (d), the EPA is authorized
to determine the BSER and to calculate the amount of emission
reduction achievable through applying the BSER. The state is
authorized to identify the standard or standards of performance that
reflects that amount of emission reduction. In addition, the state
is required to include in its state plan the standards of
performance and measures to implement and enforce those standards.
The state must submit the plan to the EPA, and the EPA must approve
the plan if the standards of performance and implementing and
enforcing measures are satisfactory. This is discussed in more
detail in Sections IV, VI, VII and VIII of this preamble, as well as
in the Legal Memorandum.
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To determine the BSER for reducing CO2 emissions at
affected EGUs, the EPA considered numerous measures that are already
being implemented and can be implemented more broadly to
[[Page 34835]]
improve emission rates and to reduce overall CO2 emissions
from fossil fuel-fired EGUs. Overall, the BSER proposed here is based
on a range of measures that fall into four main categories, or
``building blocks,'' which comprise improved operations at EGUs,
dispatching lower-emitting EGUs and zero-emitting energy sources, and
end-use energy efficiency. All of these measures have been amply
demonstrated via their current widespread use by utilities and states.
The proposed guidelines are structured so that states would not be
required to use each and every one of the measures that the EPA
determines constitute the BSER or to apply any one of those measures to
the same extent that the EPA determines is achievable at reasonable
cost. Instead, in developing its plan, each state will have the
flexibility to select the measure or combination of measures it prefers
in order to achieve its CO2 emission reduction goal. Thus, a
state could choose to achieve more reductions from one measure
encompassed by the BSER and less from another, or it could choose to
include measures that were not part of the EPA's BSER determination, as
long as the state achieves the CO2 reductions at affected
EGUs necessary to meet the goal that the EPA has defined as
representing the BSER.
As explained in further detail in Sections VI, VII and VIII of this
preamble regarding the agency's determination of the BSER, the EPA is
offering the opportunity via this proposal to comment on the proposed
BSER, the proposed methodology for computing state goals based on
application of the BSER, and the state-specific data used in the
computations. Once the final goals have been promulgated, a state would
no longer have an opportunity to request that the EPA adjust its
CO2 goal. The final state-specific CO2 goals
would reflect any adjustments as appropriate based on comments provided
to the EPA to address any data errors in the analysis for the proposed
goals. We expect that states will be able to meet the CO2
goals because they will represent the application of the BSER for the
states' affected sources.
This proposed rule sets forth the state goals that reflect the BSER
and guidelines for states to use in developing their plans to reduce
CO2 from fossil fuel-fired EGUs. The preamble describes the
proposed expectations for state plans and discusses options that the
EPA has considered. It also explains the EPA's authority to define the
BSER, as well as state goals, and each state's responsibility to
develop and implement standards of performance that will achieve its
CO2 goal. Additional detail on various aspects of the
proposal is included in several technical support documents (TSDs) and
memoranda, which are available in the rulemaking docket.
The proposal was substantially informed by the extensive input from
states and a wide range of stakeholders that the EPA sought and has
received since the summer of 2013. The EPA invites further input
through public comment on all aspects of this proposal.
2. Summary of the Proposal's Major Provisions
a. Approach
In developing this proposed rulemaking, the EPA is implementing
statutory provisions that have been in place since Congress first
enacted the CAA in 1970 and that have been implemented pursuant to
regulations promulgated in 1975 and followed in subsequent CAA section
111(d) rulemakings. These provisions ensure that, in concert with the
provisions of CAA sections 110 and 112, new and existing major
stationary sources operate in ways that address their emissions of
significant air pollutants that are harmful to public health and the
environment. These requirements call on the EPA to develop emission
guidelines, which reflect the EPA's determination of the BSER, for
states to follow in formulating compliance plans to implement standards
of performance to achieve emission reductions consistent with the BSER.
In following these provisions, the EPA is proposing a BSER based on
strategies currently being used by states and companies to reduce
CO2 emissions from EGUs.
The CAA, as interpreted by the courts, identifies several factors
for the EPA to consider in a BSER determination. These include
technical feasibility, costs, size of emission reductions and
technology (e.g., whether the system promotes the implementation and
further development of technology). In determining the BSER, the EPA
considered the reductions achievable through measures that reduce
CO2 emissions from existing fossil fuel-fired EGUs either by
(1) reducing the CO2 emission rate at those units or (2)
reducing the units' CO2 emission total to the extent that
generation can be shifted from higher-emitting fossil fuel-fired EGUs
to lower- or zero-emitting options.
As the EPA has done in making BSER determinations in previous CAA
section 111(d) rulemakings, the agency considered the types of
strategies that states and owners and operators of EGUs are already
employing to reduce the covered pollutant (in this case,
CO2) from affected sources (in this case, fossil fuel-fired
EGUs).\8\ Across the nation, many states, cities and towns, and owners
and operators of EGUs have shown leadership in creating and
implementing policies and programs that reduce CO2 emissions
from the power sector while achieving other economic, environmental and
energy benefits. Some of these activities, such as market-based
programs and GHG performance standards, directly require CO2
emission reductions from EGUs. Others reduce CO2 emissions
by reducing utilization of fossil fuel-fired EGUs through, for example,
renewable portfolio standards (RPS) and energy efficiency resource
standards (EERS). For example, currently 10 states have market-based
GHG emission programs, 38 states have renewable portfolio standards or
goals, and utilities in 47 states run demand-side energy efficiency
programs. Many individual companies also have significant voluntary
CO2 emission reduction programs.
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\8\ The final emission guidelines for landfill gas emissions
from municipal solid waste landfills, published on March 12, 1996
and amended on June 16, 1998 (61 FR 9905 and 63 FR 32743,
respectively) are one example, as they allow either of two
approaches for controlling landfill gas--by recovering the gas as a
fuel, for sale, and removing from the premises, or by destroying the
organic content of the gas on the premises using a control device.
Recovering the gas as a fuel source was a practice already being
used by some affected sources prior to promulgation of the
rulemaking.
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Such strategies--and the proposed BSER determination--reflect the
fact that, in almost all states, the production, distribution and use
of electricity can be, and is, undertaken in ways that accommodate
reductions in both pollution emission rates and total emissions.
Specifically, electricity production, at least to some extent, takes
place interchangeably between and among multiple generation facilities
and different types of generation, a fact that Congress, the EPA and
the states have long relied on in enacting or promulgating pollution
reduction programs, such as Title IV of the CAA, the NOX SIP
Call, the Cross State Air Pollution Rule (CSAPR) and RGGI.
As a result, the agency, in quantifying state goals, assessed what
combination of electricity production or energy demand reduction across
generation facilities can offer a reasonable-cost, technically feasible
approach to achieving CO2 emission reductions. States, in
turn, will be able to look broadly at opportunities across their
[[Page 34836]]
electricity system in devising plans to meet their goals. Importantly,
states may rely on measures that they already have in place, including
renewable energy standards and demand-side energy efficiency programs,
and the proposal details how such existing state programs can be
incorporated into state plans. States will also be able to participate
in multi-state programs that already exist or may create new ones.
Thus, to determine the BSER for reducing CO2 emissions
at affected EGUs and to establish the numerical goals that reflect the
BSER, the EPA considered numerous measures that can and are being
implemented to improve emission rates and to reduce or limit mass
CO2 emissions from fossil fuel-fired EGUs. These measures
encompass two basic approaches: (1) Reducing the carbon intensity of
certain affected EGUs by improving the efficiency of their operations,
and (2) addressing affected EGUs' mass emissions by varying their
utilization levels. For purposes of expressing the BSER as an emission
limitation, in this case in the form of state-level goals, we propose
to base these two approaches on measures grouped into four main
categories, or ``building blocks.'' These building blocks can also be
used as a guide to states for constructing broad-based, cost-effective,
long-term strategies to reduce CO2 emissions. The EPA
believes that the application of measures from each of the building
blocks can achieve CO2 emission reductions at fossil fuel-
fired EGUs such that, when combined with measures from other building
blocks, the measures represent the ``best system of emission reduction
. . . adequately demonstrated'' for fossil fuel-fired EGUs. The
building blocks are:
1. Reducing the carbon intensity of generation at individual
affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs
in the amount that results from substituting generation at those EGUs
with generation from less carbon-intensive affected EGUs (including
NGCC units under construction).
3. Reducing emissions from affected EGUs in the amount that results
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
4. Reducing emissions from affected EGUs in the amount that results
from the use of demand-side energy efficiency that reduces the amount
of generation required.
The four building blocks are described in detail in Sections VI of
this preamble. As explained in that section, the EPA evaluated each of
the building blocks individually against the BSER criteria and found
that each of the building blocks independently merits consideration as
part of the BSER. The EPA also evaluated combinations of the building
blocks against the BSER criteria--in particular, a combination of all
four building blocks and a combination of building blocks 1 and 2.
Based on that evaluation, the EPA proposes that the combination of
all four building blocks is the BSER. The combination of all four
blocks best represents the BSER because it achieves greater emission
reductions at a lower cost, takes better advantage of the wide range of
measures that states, cities, towns and utilities are already using to
reduce CO2 from EGUs and reflects the integrated nature of
the electricity system and the diversity of electricity generation
technology. Section VI of this preamble also explains how the EPA
considered more aggressive application of measures in each block. This
includes consideration of more extensive application of measures that
the EPA determined do represent a component of the BSER (such as more
extensive or accelerated application of demand-side measures), as well
as consideration of options in some blocks that the EPA determined
would not represent the BSER for existing sources (such as the
inclusion of retrofit carbon capture and storage or sequestration (CCS)
on existing EGUs).
As part of the BSER determination, the EPA considered the impacts
that implementation of the emission reductions based on the combination
of the blocks would have on the cost of electricity and electricity
system reliability. As the preamble details, the EPA believes that,
both with respect to the overall proposed BSER and with respect to the
individual building blocks, the associated costs are reasonable.
Importantly, the proposed BSER, expressed as a numeric goal for each
state, provides states with the flexibility to determine how to achieve
the reductions (i.e., greater reductions from one building block and
less from another) and to adjust the timing in which reductions are
achieved, in order to address key issues such as cost to consumers,
electricity system reliability and the remaining useful life of
existing generation assets.
In sum, the EPA proposes that the BSER for purposes of CAA section
111(d), as applied to existing fossil fuel-fired EGUs, is based on a
combination of measures that reduce CO2 emissions and
CO2 emission rates and encompass all four building
blocks.\9\ We are also soliciting comment on application of only the
first two building blocks as the basis for the BSER, while noting that
application of only the first two building blocks achieves fewer
CO2 reductions at a higher cost.
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\9\ The EPA notes that under the proposed BSER, some building
blocks would apply to some, but not all, affected sources.
Specifically, building block 1 would apply to affected coal-fired
steam EGUs, building block 2 would apply to all affected steam EGUs
(both coal-fired and oil/gas-fired), and building blocks 3 and 4
would apply to all affected EGUs.
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In determining the BSER, we have considered the ranges of
reductions that can be achieved by application of each building block,
and we have identified goals that we believe reflect a reasonable
degree of application of each building block consistent with the BSER
criteria. Relying on all four building blocks to characterize the
combination of measures that reduce CO2 emissions and
CO2 emission rates at affected EGUs as the basis for the
BSER is consistent with strategies, actions and measures that companies
and states are already undertaking to reduce GHG emissions and with
current trends in the electric power sector, driven by efforts to
reduce GHGs as well as by other factors, such as advancements in
technology. Reliance on all four building blocks in this way also
supports the goals of achieving significant and technically feasible
reductions of CO2 at a reasonable cost, while also promoting
technology and approaches that are important for achieving further
reductions. Finally, the EPA believes that the diverse range of
measures encompassed in the four building blocks allows states and
sources to take full advantage of the inherent flexibility of the
current regionally interconnected and integrated electricity system so
as to achieve the CO2 goals while continuing to meet the
demand for electricity services in a reliable and affordable manner.
The EPA recognizes that states differ in important ways, including
in their mix of existing EGUs and in their policy priorities.
Consequently, opportunities and preferences for reducing emissions, as
reflected in each of the building blocks, vary across states. While the
state-specific goals that the EPA is proposing in this rule are based
on consistent application of a single goal-setting methodology across
all states, the goals account for these key differences. The state-
specific CO2 goals derived from application of the
methodology vary because, in setting the goals for a state, the EPA
used data specific to each state's EGUs and certain
[[Page 34837]]
other attributes of its electricity system (e.g., current mix of
generation resources).
The proposed BSER and goal-setting methodology reflect information
provided and priorities expressed during the EPA's recent, extensive
public outreach process. The input we received ranged from the states'
desires for flexibility and recognition of varying state circumstances
to the success that states and companies have had in adopting a range
of pollution--and demand-reduction strategies. The state-specific
approach embodied in both CAA section 111(d) and this proposal
recognizes that ultimately states are the most knowledgeable about
their specific circumstances and are best positioned to evaluate and
leverage existing and new generation capacity and programs to reduce
CO2 emissions.
To meet its goal, each state will be able to design programs that
use the measures it selects, and these may include the combination of
building blocks most relevant to its specific circumstances and policy
preferences. States may also identify technologies or strategies that
are not explicitly mentioned in any of the four building blocks and may
use those technologies or strategies as part of their overall plans
(e.g., market-based trading programs or construction of new natural
combined cycle units or nuclear plants). Further, the EPA's approach
allows multi-state compliance strategies.
The agency also recognizes the important functional relationship
between the period of time over which measures are deployed and the
stringency of emission limitations those measures can achieve in a
practical and reasonable cost way. Because, for this proposal, the EPA
is proposing a 10-year period over which to achieve the full required
CO2 reductions, a period that begins more than five years
from the date of this proposal, a state could take advantage of this
relationship in the design of its program by using relevant
combinations of building blocks to achieve its state goal in a manner
that provides for electricity system reliability, avoids the creation
of stranded assets and has a reasonable cost.
b. State Goals and Flexibilities
In this action, the EPA is proposing state-specific rate-based
goals that state plans must be designed to meet. These state-specific
goals are based on an assessment of the amount of emissions that can be
reduced at existing fossil fuel-fired EGUs through application of the
BSER, as required under CAA section 111(d). The agency is proposing
state-specific final goals that must be achieved by no later than the
year 2030. The proposed final goals reflect the EPA's quantification of
adjusted state-average emission rates from affected EGUs that could be
achieved at reasonable cost by 2030 through implementation of the four
building blocks described above.
The EPA recognizes that, with many measures, states can achieve
emission reductions in the short-term, though the full effects of
implementation of other measures, such as demand-side energy efficiency
(EE) programs and the addition of renewable energy (RE) generating
capacity, can take longer. Thus, the EPA is proposing interim goals
that states must meet beginning in 2020. The proposed interim goals
would apply over a 2020-2029 phase-in period. They reflect the level of
reductions in CO2 emissions and emission rates and the
extent of the application of the building blocks that would be
presumptively approvable in a state plan during the ramp-up to
achieving the final goal.
The EPA is proposing to allow each state flexibility with regard to
the form of the goal. A state could adopt the rate-based form of the
goal established by the EPA or an equivalent mass-based form of the
goal. A multi-state approach incorporating either a rate- or mass-based
goal would also be approvable based upon a demonstration that the
state's plan would achieve the equivalent in stringency, including
compliance timing, to the state-specific rate-based goal set by the
EPA.
We believe that this approach to establishing requirements for
states in developing their plans responds both to the needs of an
effectively implemented program and to the range of viewpoints
expressed by stakeholders regarding the simultaneous need for both
flexibility and clear guidance on what would constitute an approvable
state plan. We likewise believe that this approach represents a
reasonable balance between two competing objectives grounded in CAA
section 111(d)--a need for rigor and consistency in calculating
emission reductions reflecting the BSER and a need to provide the
states with flexibility in establishing and implementing the standards
of performance that reflect those emission reductions. The importance
of this balance is heightened by the fact that the operations of the
electricity system itself rely on the flexibility made available and
achieved through dispatching between and among multiple interconnected
EGUs, demand management and end-use energy efficiency. We view the
proposed goals as providing rigor where required by the statute with
respect to the amount of emission reductions, while providing states
with flexibility where permitted by the statute, particularly with
respect to the range of measures that a state could include in its
plan. This approach recognizes that state plans for emission reductions
can, and must, be consistent with a vibrant and growing economy and
supply of reliable, affordable electricity to support that economy. It
further reflects the growing trend, as exemplified by many state and
local clean energy policies and programs, to shift energy production
away from carbon-intensive fuels to a modern, more sustainable system
that puts greater reliance on renewable energy, energy efficiency and
other low-carbon energy options.
c. State Plans
i. Plan Approach
Each state will determine, and include in its plan, emission
performance levels for its affected EGUs that are equivalent to the
state-specific CO2 goal in the emission guidelines, as well
as the measures needed to achieve those levels and the overall goal. As
part of determining these levels, the state will decide whether it will
adopt the rate-based form of the goal established by the EPA or
translate the rate-based goal to a mass-based goal. The state must then
establish a standard, or set of standards, of performance, as well as
implementing and enforcing measures, to achieve the emission
performance level specified in the state plan. The state may choose the
measures it will include in its plan to achieve its goal. The state may
use the same set of measures as in the EPA's approach to setting the
goals, or the state may use other or additional measures to achieve the
required CO2 reductions.
A state plan must include enforceable CO2 emission
limits that apply to affected EGUs. In doing so, a state plan may take
a portfolio approach, which could include enforceable CO2
emission limits that apply to affected EGUs as well as other
enforceable measures, such as RE and demand-side EE measures, that
avoid EGU CO2 emissions and are implemented by the state or
by another entity. The plan must also include a process for reporting
on plan implementation, progress toward achieving CO2 goals,
and implementation of corrective actions, if necessary. No less
frequently than every two rolling calendar years, beginning January 1,
2022, the state will be required to compare emission performance
achieved by affected EGUs
[[Page 34838]]
in the state with the emissions performance projected in the state
plan, and report that to the EPA.
In this action, the EPA is also proposing guidelines for states to
follow in developing their plans. These guidelines include
approvability criteria, requirements for state plan components, the
process and timing for state plan submittal and the process and timing
for demonstrating achievement of the CO2 emission
performance level in the state plan. The proposed guidelines provide
states with options for meeting the state-specific goals established by
the EPA in a flexible manner that accommodates a diverse range of state
approaches. The plan guidelines provide the states with the ability to
achieve the full reductions over a multi-year period, through a variety
of reduction strategies, using state-specific or multi-state approaches
that can be achieved on either a rate or mass basis. They also address
several key policy considerations that states can be expected to
contemplate in developing their plans.
With respect to the structure of the state plans, the EPA, in its
extensive outreach efforts, heard from a wide range of stakeholders
that the EPA should authorize state plans to include a portfolio of
actions that encompass a diverse set of programs and measures that
achieve either a rate-based or mass-based emission performance level
for affected EGUs but that do not place legal responsibility for
achieving the entire amount of the emission performance level on the
affected EGUs. In view of this strong sentiment from stakeholders, the
EPA is proposing that state plans that take this portfolio approach
would be approvable, provided that they meet other key requirements
such as achieving the required emission reductions over the appropriate
timeframes. Plans that do directly assure that affected EGUs achieve
all of the required emission reductions (such as the mass-based
programs being implemented in California and the RGGI states) would
also be approvable provided that they meet other key requirements, such
as achieving the required emission reductions over the appropriate
timeframes.
ii. State Plan Components
The EPA is proposing to evaluate and approve state plans based on
four general criteria: (1) Enforceable measures that reduce EGU
CO2 emissions; (2) projected achievement of emission
performance equivalent to the goals established by the EPA, on a
timeline equivalent to that in the emission guidelines; (3)
quantifiable and verifiable emission reductions; and (4) a process for
reporting on plan implementation, progress toward achieving
CO2 goals, and implementation of corrective actions, if
necessary. In addition, each state plan must follow the EPA framework
regulations at 40 CFR 60.23. The proposed components of states plans
are:
Identification of affected entities
Description of plan approach and geographic scope
Identification of state emission performance level
Demonstration that plan is projected to achieve emission
performance level
Identification of emission standards
Demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable
Identification of monitoring, reporting, and recordkeeping
requirements
Description of state reporting
Identification of milestones
Identification of backstop measures
Certification of hearing on state plan
Supporting material
iii. Process for State Plan Submittal and Review
Recognizing the urgent need for actions to reduce GHG emissions,
and in accordance with the Presidential Memorandum,\10\ the EPA expects
to finalize this rulemaking by June 1, 2015. The Presidential
Memorandum also calls for a deadline of June 30, 2016, for states to
submit their state plans. The EPA is proposing that each state must
submit a plan to the EPA by June 30, 2016. However, the EPA recognizes
that some states may need more than one year to complete all of the
actions needed for their final state plans, including technical work,
state legislative and rulemaking activities, coordination with third
parties, and coordination among states involved in multi-state plans.
Therefore, the EPA is proposing an optional two-phased submittal
process for state plans. Each state would be required to submit a plan
by June 30, 2016, that contains certain required components. If a state
needs additional time to submit a complete plan, then the state must
submit an initial plan by June 30, 2016 that documents the reasons the
state needs more time and includes commitments to concrete steps that
will ensure that the state will submit a complete plan by June 30, 2017
or 2018, as appropriate. To be approvable, the initial plan must
include specific components, including a description of the plan
approach, initial quantification of the level of emission performance
that will be achieved in the plan, a commitment to maintain existing
measures that limit CO2 emissions, an explanation of the
path to completion, and a summary of the state's response to any
significant public comment on the approvability of the initial plan, as
described in Section VIII.E of this preamble.
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\10\ Presidential Memorandum--Power Sector Carbon Pollution
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
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If the initial plan includes those components and if the EPA does
not notify the state that the initial plan does not contain the
required components, the extension of time to submit a complete plan
will be deemed granted and a state would have until June 30, 2017, to
submit a complete plan if the geographic scope of the plan is limited
to that state. If the state develops a plan that includes a multi-state
approach, it would have until June 30, 2018 to submit a complete plan.
Further, the EPA is proposing that states participating in a multi-
state plan may submit a single joint plan on behalf of all of the
participating states.
Following submission of final plans, the EPA will review plan
submittals for approvability. Given the diverse approaches states may
take to meet the emission performance goals in the emission guidelines,
the EPA is proposing to extend the period for EPA review and approval
or disapproval of plans from the four-month period provided in the EPA
framework regulations to a twelve-month period.
iv. Timing of Compliance
As states, industry groups and other stakeholders have made clear,
the EPA recognizes that the measures states have been and will be
taking to reduce CO2 emissions from existing EGUs can take
time to implement. Thus, we are proposing that, while states must begin
to make reductions by 2020, full compliance with the CO2
emission performance level in the state plan must be achieved by no
later than 2030. Under this proposed option, a state would need to meet
an interim CO2 emission performance level on average over
the 10-year period from 2020-2029, as well as achieve its final
CO2 emission performance level by 2030 and maintain that
level subsequently. This proposed option is based on the application of
a range of measures from all four building blocks, and the agency
believes that this approach for compliance timing is reasonable and
appropriate and would best support the optimization of overall
[[Page 34839]]
CO2 reductions. The agency is also requesting comment on an
alternative option, a 5-year period for compliance, in combination with
a less stringent set of CO2 emission performance levels.
These options are fully described in Section VIII of this preamble, and
the state goals associated with the alternative option are described in
Section VII.E of this preamble. The EPA is also seeking comment on
different combinations of building blocks and different levels of
stringency for each building block.
The EPA is also proposing that measures that a state takes after
the date of this proposal, or programs already in place, which result
in CO2 emission reductions during the 2020-2030 period,
would apply toward achievement of the state's 2030 CO2
emission goal. Thus, states with currently existing programs and
policies, and states that put in place new programs and policies early,
will be better positioned to achieve the goals.
v. Resources for States
To respond to requests from states for methodologies, tools and
information to assist them in designing and implementing their plans,
the EPA, in consultation with the U.S. Department of Energy and other
federal agencies, as well as states, is collecting and developing
available resources and is making those resources available to the
states via a dedicated Web site.\11\ As we and others continue to
develop tools, templates and other resources, we will update the Web
site. We intend, during the public comment period, to work actively
with the states on resources that will be helpful to them in both
developing and implementing their plans.
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\11\ www2.epa.gov/cleanpowerplantoolbox.
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3. Projected National-Level Emission Reductions
Under the proposed guidelines, the EPA projects annual
CO2 reductions of 26 to 30 percent below 2005 levels
depending upon the compliance year. These guidelines will also result
in important reductions in emissions of criteria air pollutants,
including sulfur dioxide (SO2), nitrogen oxides
(NOX) and directly emitted fine particulate matter
(PM2.5). A thorough discussion of the EPA's analysis is
presented in Section X.A of this preamble and in Chapter 3 of the
Regulatory Impact Analysis (RIA) included in the docket for this
rulemaking.
4. Costs and Benefits
Actions taken to comply with the proposed guidelines will reduce
emissions of CO2 and other air pollutants, including
SO2, NOX and directly emitted PM2.5,
from the electric power industry. States will make the ultimate
determination as to how the emission guidelines are implemented. Thus,
all costs and benefits reported for this action are illustrative
estimates. The EPA has calculated illustrative costs and benefits in
two ways: One based on an assumption of individual state plans and
another based on an assumption that states will opt for multi-state
plans. The illustrative costs and benefits are based upon compliance
approaches that reflect a range of measures consisting of improved
operations at EGUs, dispatching lower-emitting EGUs and zero-emitting
energy sources, and increasing levels of end-use energy efficiency.
Assuming that states comply with the guidelines collaboratively
(referred to as the regional compliance approach), the EPA estimates
that, in 2020, this proposal will yield monetized climate benefits of
approximately $17 billion (2011$) using a 3 percent discount rate
(model average) relative to the 2020 base case, as shown in Table
1.\12\ The air pollution health co-benefits associated with reducing
exposure to ambient PM2.5 and ozone through emission
reductions of precursor pollutants in 2020 are estimated to be $16
billion to $37 billion using a 3 percent discount rate and $15 billion
to $34 billion (2011$) using a 7 percent discount rate relative to the
2020 base case. The annual compliance costs are estimated using the
Integrated Planning Model (IPM) and include demand-side energy
efficiency program and participant costs as well as monitoring,
reporting and recordkeeping costs. In 2020, total compliance costs of
this proposal are approximately $5.5 billion (2011$). The quantified
net benefits (the difference between monetized benefits and compliance
costs) in 2020 are estimated to be $28 billion to $49 billion (2011$)
using a 3 percent discount rate (model average). As reflected in Table
2, climate benefits are approximately $30 billion in 2030 using a 3
percent discount rate (model average, 2011$) relative to the 2030 base
case assuming a regional compliance approach for the proposal. Health
co-benefits are estimated to be approximately $25 to $59 billion (3
percent discount rate) and $23 to $54 billion (7 percent discount rate)
relative to the 2030 base case (2011$). In 2030, total compliance costs
for the proposed option regional approach are approximately $7.3
billion (2011$). The net benefits for this proposal increase to
approximately $48 billion to $82 billion (3 percent discount rate model
average, 2011$) in 2030 for the proposed option regional compliance
approach.
---------------------------------------------------------------------------
\12\ The EPA has used social cost of carbon (SCC) estimates--
i.e., the monetary value of impacts associated with a marginal
change in CO2 emissions in a given year--to analyze
CO2 climate impacts of this rulemaking. The four SCC
estimates are associated with different discount rates (model
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
percentile at 3 percent), and each increases over time. In this
summary, the EPA provides the estimate of climate benefits
associated with the SCC value deemed to be central: The model
average at 3 percent discount rate.
---------------------------------------------------------------------------
In comparison, if states choose to comply with the guidelines on a
state-specific basis (referred to as state compliance approach), the
climate benefits in 2020 are expected to be approximately $18 billion
(3 percent discount rate, model average, 2011$), as Table 1 shows.
Health co-benefits are estimated to be $17 to $40 billion (3 percent
discount rate) and $15 to $36 billion (7 percent discount rate). Total
compliance costs are approximately $7.5 billion annually in 2020. Net
benefits in 2020 are estimated to be $27 to $50 billion (3 percent
model average discount rate, 2011$). In 2030, as shown on Table 2,
climate benefits are approximately $31 billion using a 3 percent
discount rate (model average, 2011$) relative to the 2030 base case
assuming a state compliance approach. Health co-benefits are estimated
to be approximately $27 to $62 billion (3 percent discount rate) and
$24 to $56 billion (7 percent discount rate) relative to the 2030 base
case (2011$). In 2030, total compliance costs for the state approach
are approximately $8.8 billion (2011$). In 2030, these net benefits are
estimated to be approximately $49 to $84 billion (3 percent discount
rate, 2011$) assuming a state compliance approach.
[[Page 34840]]
Table 1--Summary of the Monetized Benefits, Compliance Costs, and Net
Benefits for the Proposed Guidelines in 2020 \a\
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Proposed Guidelines Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............ $17.
---------------------------------------
Air pollution health co-benefits $16 to $37........ $15 to $34.
\c\.
Total Compliance Costs \d\...... $5.5.............. $5.5.
Net Monetized Benefits \e\...... $28 to $49........ $26 to $45.
---------------------------------------
Non-monetized Benefits.......... Direct exposure to SO2 and NO2.
1.3 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
Proposed Guidelines State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............ $18
---------------------------------------
Air pollution health co-benefits $17 to $40........ $15 to $36.
\c\.
Total Compliance Costs \d\...... $7.5.............. $7.5.
Net Monetized Benefits \e\...... $27 to $50........ $26 to $46.
---------------------------------------
Non-monetized Benefits.......... Direct exposure to SO2 and NO2.
1.5 tons.
Ecosystem effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3% discount
rate, however we emphasize the importance and value of considering the
full range of SCC values. As shown in the RIA, climate benefits are
also estimated using the other three SCC estimates (model average at
2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile
at 3 percent). The SCC estimates are year-specific and increase over
time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed
guidelines and a discount rate of approximately 5%. This estimate
includes monitoring, recordkeeping, and reporting costs and demand
side energy efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
Table 2--Summary of the Monetized Benefits, Compliance Costs, and Net
Benefits for the Proposed Guidelines in 2030 \a\
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Proposed Guidelines Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............ $30.
---------------------------------------
Air pollution health co-benefits $25 to $59........ $23 to $54.
\c\.
Total Compliance Costs \d\...... $7.3.............. $7.3.
Net Monetized Benefits \e\...... $48 to $82........ $46 to $77.
---------------------------------------
Non-monetized Benefits.......... Direct exposure to SO2 and NO2.
1.7 tons of Hg and 580 tons of HCl.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
Proposed Guidelines State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\............ $31.
------------------------------------------------------------------------
Air pollution health co-benefits $27 to $62........ $24 to $56.
\c\.
Total Compliance Costs \d\...... $8.8.............. $8.8.
Net Monetized Benefits \e\...... $49 to $84........ $46 to $79.
------------------------------------------------------------------------
[[Page 34841]]
Non-monetized Benefits.......... Direct exposure to SO2 and NO2.
2.1 tons of Hg and 590 tons of HCl.
Ecosystem effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2030, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3% discount
rate, however we emphasize the importance and value of considering the
full range of SCC values. As shown in the RIA, climate benefits are
also estimated using the other three SCC estimates (model average at
2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile
at 3 percent). The SCC estimates are year-specific and increase over
time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed
guidelines and a discount rate of approximately 5%. This estimate
includes monitoring, recordkeeping, and reporting costs and demand
side energy efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
There are additional important benefits that the EPA could not
monetize. These unquantified benefits include climate benefits from
reducing emissions of non-CO2 greenhouse gases (e.g.,
nitrous oxide and methane) \13\ and co-benefits from reducing direct
exposure to SO2, NOX and hazardous air pollutants
(e.g., mercury and hydrogen chloride), as well as from reducing
ecosystem effects and visibility impairment.
---------------------------------------------------------------------------
\13\ Although CO2 is the predominant greenhouse gas
released by the power sector, electricity generating units also emit
small amounts of nitrous oxide and methane. See RIA Chapter 2 for
more detail about power sector emissions and the U.S. Greenhouse Gas
Reporting Program's power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.html.
---------------------------------------------------------------------------
In addition to the cost and benefits of the rule, the EPA projects
the employment impacts of the guidelines. We project job gains and
losses relative to base case for the electric generation, coal and
natural gas production, and demand side energy efficiency sectors. In
2020, we project job growth of 25,900 to 28,000 job-years \14\ in the
power production and fuel extraction sectors, and we project an
increase of 78,800 jobs in the demand-side energy efficiency sector.
---------------------------------------------------------------------------
\14\ A job-year is not an individual job; rather, a job-year is
the amount of work performed by the equivalent of one full-time
individual for one year. For example, 20 job-years in 2020 may
represent 20 full-time jobs or 40 half-time jobs.
---------------------------------------------------------------------------
Based upon the foregoing, it is clear that the monetized benefits
of this proposal are substantial and far outweigh the costs.
B. Organization and Approach for This Proposed Rule
This action presents the EPA's proposed emission guidelines for
states to consider in developing plans to reduce GHG emissions from the
electric power sector. Section II provides background on climate change
impacts from GHG emissions, GHG emissions from fossil fuel-fired EGUs
and the utility power sector and CAA section 111(d) requirements.
Section III presents a summary of the EPA's stakeholder outreach
efforts, key messages provided by stakeholders, state policies and
programs that reduce GHG emissions, and conclusions. In Section IV of
the preamble, we present a summary of the rule requirements and the
legal basis for these. Section V explains the EPA authority to regulate
CO2 and EGUs, identifies affected sources, and describes the
proposed treatment of source categories. Section VI describes the use
of building blocks for setting state goals and key considerations in
doing so. Sections VII and VIII provide explanations of the proposed
state-specific goals and the proposed requirements for state plans,
respectively. Implications for the new source review and Title V
programs and potential interactions with other EPA rules are described
in Section IX. Impacts of the proposed action are then described in
Section X, followed by a discussion of statutory and executive order
reviews in Section XI and the statutory authority for this action in
Section XII.
We note that this rulemaking overlaps in certain respects with two
other related rulemakings: The January 2014 proposed rulemaking that
the EPA published on January 8, 2014 for CO2 emissions from
newly constructed affected sources,\15\ and the rulemaking for modified
and reconstructed sources that the EPA is proposing at the same time as
this rulemaking. Each of these three rulemakings is independent of the
other two, and each has its own rulemaking docket. Accordingly,
commenters who wish to comment on any aspect of this rulemaking,
including a topic that overlaps an aspect of one or both of the other
two related rulemakings, should make those comments on this rulemaking.
---------------------------------------------------------------------------
\15\ 79 FR 1430.
---------------------------------------------------------------------------
II. Background
In this section, we discuss climate change impacts from GHG
emissions, both on public health and public welfare, present
information about GHG emissions from fossil fuel fired EGUs, and
summarize the statutory and regulatory requirements relevant to this
rulemaking.
A. Climate Change Impacts From GHG Emissions
In 2009, the EPA Administrator issued the document known as the
Endangerment Finding under CAA section 202(a)(1).\16\ In the
Endangerment Finding, which focused on public health and public welfare
impacts within the United States, the Administrator found that elevated
concentrations of GHGs in the atmosphere may reasonably be anticipated
to endanger public health and welfare of current and future
generations. We summarize these adverse effects on public health and
welfare briefly here.
---------------------------------------------------------------------------
\16\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66,496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------
1. Public Health Impacts Detailed in the 2009 Endangerment Finding
Climate change caused by human emissions of GHGs threatens public
health in multiple ways. By raising average temperatures, climate
change
[[Page 34842]]
increases the likelihood of heat waves, which are associated with
increased deaths and illnesses. While climate change also increases the
likelihood of reductions in cold-related mortality, evidence indicates
that the increases in heat mortality will be larger than the decreases
in cold mortality in the United States. Compared to a future without
climate change, climate change is expected to increase ozone pollution
over broad areas of the U.S., including in the largest metropolitan
areas with the worst ozone problems, and thereby increase the risk of
morbidity and mortality. Other public health threats also stem from
projected increases in intensity or frequency of extreme weather
associated with climate change, such as increased hurricane intensity,
increased frequency of intense storms, and heavy precipitation.
Increased coastal storms and storm surges due to rising sea levels are
expected to cause increased drownings and other health impacts.
Children, the elderly, and the poor are among the most vulnerable to
these climate-related health effects.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
Climate change caused by human emissions of GHGs also threatens
public welfare in multiple ways. Climate changes are expected to place
large areas of the country at serious risk of reduced water supplies,
increased water pollution, and increased occurrence of extreme events
such as floods and droughts. Coastal areas are expected to face
increased risks from storm and flooding damage to property, as well as
adverse impacts from rising sea level, such as land loss due to
inundation, erosion, wetland submergence and habitat loss. Climate
change is expected to result in an increase in peak electricity demand,
and extreme weather from climate change threatens energy,
transportation, and water resource infrastructure. Climate change may
exacerbate ongoing environmental pressures in certain settlements,
particularly in Alaskan indigenous communities. Climate change also is
very likely to fundamentally rearrange U.S. ecosystems over the 21st
century. Though some benefits may balance adverse effects on
agriculture and forestry in the next few decades, the body of evidence
points towards increasing risks of net adverse impacts on U.S. food
production, agriculture and forest productivity as temperature
continues to rise. These impacts are global and may exacerbate problems
outside the U.S. that raise humanitarian, trade, and national security
issues for the U.S.
3. New Scientific Assessments
As outlined in Section VIII.A. of the 2009 Endangerment Finding,
the EPA's approach to providing the technical and scientific
information to inform the Administrator's judgment regarding the
question of whether GHGs endanger public health and welfare was to rely
primarily upon the recent, major assessments by the U.S. Global Change
Research Program (USGCRP), the Intergovernmental Panel on Climate
Change (IPCC), and the National Research Council (NRC) of the National
Academies. These assessments addressed the scientific issues that the
EPA was required to examine, were comprehensive in their coverage of
the GHG and climate change issues, and underwent rigorous and exacting
peer review by the expert community, as well as rigorous levels of U.S.
government review. Since the administrative record concerning the
Endangerment Finding closed following the EPA's 2010 Reconsideration
Denial, a number of such assessments have been released. These
assessments include the IPCC's 2012 ``Special Report on Managing the
Risks of Extreme Events and Disasters to Advance Climate Change
Adaptation'' (SREX) and the 2013-2014 Fifth Assessment Report (AR5),
the USGCRP's 2014 ``Climate Change Impacts in the United States''
(Climate Change Impacts), and the NRC's 2010 ``Ocean Acidification: A
National Strategy to Meet the Challenges of a Changing Ocean'' (Ocean
Acidification), 2011 ``Report on Climate Stabilization Targets:
Emissions, Concentrations, and Impacts over Decades to Millennia''
(Climate Stabilization Targets), 2011 ``National Security Implications
for U.S. Naval Forces'' (National Security Implications), 2011
``Understanding Earth's Deep Past: Lessons for Our Climate Future''
(Understanding Earth's Deep Past), 2012 ``Sea Level Rise for the Coasts
of California, Oregon, and Washington: Past, Present, and Future'',
2012 ``Climate and Social Stress: Implications for Security Analysis''
(Climate and Social Stress), and 2013 ``Abrupt Impacts of Climate
Change'' (Abrupt Impacts) assessments.
The EPA has reviewed these new assessments and finds that the
improved understanding of the climate system they present strengthens
the case that GHGs endanger public health and welfare.
In addition, these assessments highlight the urgency of the
situation as the concentration of CO2 in the atmosphere
continues to rise. Absent a reduction in emissions, a recent National
Research Council of the National Academies assessment projected that
concentrations by the end of the century would increase to levels that
the Earth has not experienced for millions of years.\17\ In fact, that
assessment stated that ``the magnitude and rate of the present
greenhouse gas increase place the climate system in what could be one
of the most severe increases in radiative forcing of the global climate
system in Earth history.'' \18\
---------------------------------------------------------------------------
\17\ National Research Council, Understanding Earth's Deep Past,
p. 1.
\18\ Id., p.138.
---------------------------------------------------------------------------
What this means, as stated in another NRC assessment, is that:
Emissions of carbon dioxide from the burning of fossil fuels
have ushered in a new epoch where human activities will largely
determine the evolution of Earth's climate. Because carbon dioxide
in the atmosphere is long lived, it can effectively lock Earth and
future generations into a range of impacts, some of which could
become very severe. Therefore, emission reductions choices made
today matter in determining impacts experienced not just over the
next few decades, but in the coming centuries and millennia.\19\
---------------------------------------------------------------------------
\19\ National Research Council, Climate Stabilization Targets,
p. 3.
Moreover, due to the time-lags inherent in the Earth's climate, the
Climate Stabilization Targets assessment notes that the full warming
from any given concentration of CO2 reached will not be
realized for several centuries.
The recently released USGCRP ``Climate Change Impacts'' assessment
\20\ emphasizes that climate change is already happening now and it is
happening in the United States. The assessment documents the increases
in some extreme weather and climate events in recent decades, the
damage and disruption to infrastructure and agriculture, and projects
continued increases in impacts across a wide range of peoples, sectors,
and ecosystems.
---------------------------------------------------------------------------
\20\ U.S. Global Change Research Program, Climate Change Impacts
in the United States: The Third National Climate Assessment, May
2014 Available at http://nca2014.globalchange.gov/.
---------------------------------------------------------------------------
These assessments underscore the urgency of reducing emissions now:
Today's emissions will otherwise lead to raised atmospheric
concentrations for thousands of years, and raised Earth system
temperatures for even longer. Emission reductions today will benefit
the public health and public welfare of current and future generations.
Finally, it should be noted that the concentration of carbon
dioxide in the atmosphere continues to rise dramatically. In 2009, the
year of the Endangerment Finding, the average concentration of carbon
dioxide as
[[Page 34843]]
measured on top of Mauna Loa was 387 parts per million.\21\ The average
concentration in 2013 was 396 parts per million. And the monthly
concentration in April of 2014 was 401 parts per million, the first
time a monthly average has exceeded 400 parts per million since record
keeping began at Mauna Loa in 1958, and for at least the past 800,000
years according to ice core records.\22\
---------------------------------------------------------------------------
\21\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
\22\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
---------------------------------------------------------------------------
B. GHG Emissions From Fossil Fuel-Fired EGUs
Fossil fuel-fired electric utility generating units (EGUs) are by
far the largest emitters of GHGs, primarily in the form of
CO2, among stationary sources in the U.S., and among fossil
fuel-fired units, coal-fired units are by far the largest emitters.
This section describes the amounts of those emissions and places those
amounts in the context of the national inventory of GHGs.
The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \23\ (the U.S. GHG Inventory) to comply with
commitments under the United Nations Framework Convention on Climate
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sectors. It provides the information in Table 3
below, which presents total U.S. anthropogenic emissions and sinks \24\
of GHGs, including CO2 emissions, for the years 1990, 2005
and 2012.
---------------------------------------------------------------------------
\23\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2012'', Report EPA 430-R-14-003, United States Environmental
Protection Agency, April 15, 2014.
\24\ Sinks are a physical unit or process that stores GHGs, such
as forests or underground or deep sea reservoirs of carbon dioxide.
Table 3--U.S. GHG Emissions and Sinks by Sector
[Teragram carbon dioxide equivalent (Tg CO2 Eq.)] \25\
----------------------------------------------------------------------------------------------------------------
Sector 1990 2005 2012
----------------------------------------------------------------------------------------------------------------
Energy.......................................................... 5,260.1 6,243.5 5,498.9
Industrial Processes............................................ 316.1 334.9 334.4
Solvent and Other Product Use................................... 4.4 4.4 4.4
Agriculture..................................................... 473.9 512.2 526.3
Land Use, Land-Use Change and Forestry.......................... 13.7 25.5 37.8
Waste........................................................... 165.0 133.2 124.0
-----------------------------------------------
Total Emissions................................................. 6,233.2 7,253.8 6,525.6
Land Use, Land-Use Change and Forestry (Sinks).................. (831.3) (1,030.7) (979.3)
-----------------------------------------------
Net Emissions (Sources and Sinks)............................... 5,402.1 6,223.1 5,546.3
----------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\25\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2012, Report EPA 430-R-14-003, United
States Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------
Total fossil energy-related CO2 emissions (including
both stationary and mobile sources) are the largest contributor to
total U.S. GHG emissions, representing 77.7 percent of total 2012 GHG
emissions.\26\ In 2012, fossil fuel combustion by the electric power
sector--entities that burn fossil fuel and whose primary business is
the generation of electricity--accounted for 38.7 percent of all
energy-related CO2 emissions.\27\ Table 4 below presents
total CO2 emissions from fossil fuel-fired EGUs, for years
1990, 2005 and 2012.
---------------------------------------------------------------------------
\26\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2012'', Report EPA 430-R-14-003, United
States Environmental Protection Agency, April 15, 2014.
\27\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States
Environmental Protection Agency, April 15, 2014.
Table 4--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels
[Tg CO2] \28\
----------------------------------------------------------------------------------------------------------------
GHG emissions 1990 2005 2012
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel combustion EGUs...................... 1,820.8 2,402.1 2,022.7
--from coal................................................. 1,547.6 1,983.8 1,511.2
--from natural gas.......................................... 175.3 318.8 492.2
--from petroleum............................................ 97.5 99.2 18.8
----------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\28\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2012'', Report EPA 430-R-14-003, United States
Environmental Protection Agency, April 15, 2014.
---------------------------------------------------------------------------
C. The Utility Power Sector
Electricity in the United States is generated by a range of
sources--from power plants that use fossil fuels like coal, oil, and
natural gas, to non-fossil sources, such as nuclear, solar, wind and
hydroelectric power. In 2013, over 67 percent of power in the U.S. was
generated from the combustion of coal, natural gas, and other fossil
fuels, over 40 percent from coal and over 26 percent from natural
gas.\29\ In recent years, though, the proportion of new renewable
generation coming on line has increased dramatically. For instance,
over 38 percent of new generating capacity (over 5 GW out of 13.5 GW)
built in 2013 used renewable power generation technologies.\30\
---------------------------------------------------------------------------
\29\ U.S. Energy Information Administration (EIA), ``Table 7.2b
Electricity Net Generation: Electric Power Sector Electric Power
Sector,'' data from April 2014 Monthly Energy Review, release date
April 25, 2014. Available at: http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&freq=m.
\30\ Based on Table 6.3 (New Utility Scale Generating Units by
Operating Company, Plant, Month, and Year) of the U.S. Energy
Information Administration (EIA) Electric Power Monthly, data for
December 2013, for the following renewable energy sources: solar,
wind, hydro, geothermal, landfill gas, and biomass. Available at:
http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_03.
---------------------------------------------------------------------------
[[Page 34844]]
This range of different power plants generates electricity that is
transmitted and distributed through a complex system of interconnected
components to industrial, business, and residential consumers.
The utility power sector is unique in that, unlike other sectors
where the sources operate independently and on a local scale, power
sources operate in a complex, interconnected grid system that typically
is regional in scale. In addition, the U.S. economy depends on this
sector for a reliable supply of power at a reasonable cost.
In the U.S., much of the existing power generation fleet in the
infrastructure is aging. There has been, and continues to be,
technological advancement in many areas, including energy efficiency,
solar power generation, and wind power generation. Advancements and
innovation in power sector technologies provide the opportunity to
address CO2 emission levels at affected power plants while
at the same time improving the overall power system in the U.S. by
lowering the carbon intensity of power generation, and ensuring a
continued reliable supply of power at a reasonable cost.
D. Statutory and Regulatory Requirements
Clean Air Act section 111, which Congress enacted as part of the
1970 Clean Air Act Amendments, establishes mechanisms for controlling
emissions of air pollutants from stationary sources. This provision
requires the EPA to promulgate a list of categories of stationary
sources that the Administrator, in his or her judgment, finds ``causes,
or contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' \31\ The EPA has
listed more than 60 stationary source categories under this
provision.\32\ Once the EPA lists a source category, the EPA must,
under CAA section 111(b)(1)(B), establish ``standards of performance''
for emissions of air pollutants from new sources in the source
categories.\33\ These standards are known as new source performance
standards (NSPS), and they are national requirements that apply
directly to the sources subject to them.
---------------------------------------------------------------------------
\31\ CAA Sec. 111(b)(1)(A).
\32\ See 40 CFR 60 subparts Cb-OOOO.
\33\ CAA Sec. 111(b)(1)(B), 111(a)(1).
---------------------------------------------------------------------------
When the EPA establishes NSPS for new sources in a particular
source category, the EPA is also required, under CAA section 111(d)(1),
to prescribe regulations for states to submit plans regulating existing
sources in that source category for any air pollutant that, in general,
is not regulated under the CAA section 109 requirements for the NAAQS
or regulated under the CAA section 112 requirements for hazardous air
pollutants (HAP). CAA section 111(d)'s mechanism for regulating
existing sources differs from the one that CAA section 111(b) provides
for new sources because CAA section 111(d) contemplates states
submitting plans that establish ``standards of performance'' for the
affected sources and that contain other measures to implement and
enforce those standards.
``Standards of performance'' are defined under CAA section
111(a)(1) as standards for emissions that reflect the emission
limitation achievable from the ``best system of emission reduction,''
considering costs and other factors, that ``the Administrator
determines has been adequately demonstrated.'' CAA section 111(d)(1)
grants states the authority, in applying a standard of performance to
particular sources, to take into account the source's remaining useful
life or other factors.
Under CAA section 111(d), a state must submit its plan to the EPA
for approval, and the EPA must approve the state plan if it is
``satisfactory.'' \34\ If a state does not submit a plan, or if the EPA
does not approve a state's plan, then the EPA must establish a plan for
that state.\35\ Once a state receives the EPA's approval for its plan,
the provisions in the plan become federally enforceable against the
entity responsible for noncompliance, in the same manner as the
provisions of an approved SIP under CAA section 110. Although affected
EGUs located in Indian country operate as part of the interconnected
system of electricity production and distribution, those EGUs would not
be encompassed within a state's CAA section 111(d) plan. Instead, a
tribe that has one or more affected EGUs located in its area of Indian
country \36\ would have the opportunity, but not the obligation, to
establish a plan that establishes standards of performance for
CO2 emissions from affected EGUs for its tribal lands.
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\34\ CAA section 111(d)(2)(A).
\35\ CAA section 111(d)(2)(A).
\36\ The EPA is aware of at least four affected sources located
in Indian Country: Two on Navajo lands--the Navajo Generating
Station and the Four Corners Generating Station; one on Ute lands--
the Bonanza Generating Station; and one on Fort Mojave lands, the
South Point Energy Center. The affected EGUs at the first three
plants are coal-fired EGUs. The fourth affected EGU is an NGCC
facility.
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The EPA issued regulations implementing CAA section 111(d) in
1975,\37\ and has revised them in the years since.\38\ (We refer to the
regulations generally as the implementing regulations, and we refer to
the 1975 rulemaking as the framework regulations.) These regulations
provide that, in promulgating requirements for sources under CAA
section 111(d), the EPA first develops regulations known as ``emission
guidelines,'' which establish binding requirements that states must
address when they develop their plans.\39\ The implementing regulations
also establish timetables for state and EPA action: States must submit
state plans within 9 months of the EPA's issuance of the
guidelines,\40\ and the EPA must take final action on the state plans
within 4 months of the due date for those plans,\41\ although the EPA
has authority to extend those deadlines.\42\ In the present rulemaking,
the EPA is following the requirements of the implementing regulations,
and is not re-opening them, except that the EPA is extending the
timetables, as described below.
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\37\ ``State Plans for the Control of Certain Pollutants From
Existing Facilities,'' 40 FR 53,340 (Nov. 17, 1975).
\38\ The most recent amendment was in 77 FR 9304 (Feb. 16,
2012).
\39\ 40 CFR 60.22. In the 1975 rulemaking, the EPA explained
that it used the term ``emissions guidelines''--instead of emissions
limitations--to make clear that guidelines would not be binding
requirements applicable to the sources, but instead are ``criteria
for judging the adequacy of State plans.'' 40 FR at 53,343.
\40\ 40 CFR 60.23(a)(1).
\41\ 40 CFR 60.27(b).
\42\ See 40 CFR 60.27(a).
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Over the last forty years, under CAA section 111(d), the agency has
regulated four pollutants from five source categories (i.e., sulfuric
acid plants (acid mist), phosphate fertilizer plants (fluorides),
primary aluminum plants (fluorides), Kraft pulp plants (total reduced
sulfur), and municipal solid waste landfills (landfill gases)).\43\ In
addition, the agency has regulated additional pollutants under CAA
section 111(d) in conjunction with CAA
[[Page 34845]]
section 129.\44\ The agency has not previously regulated CO2
or any other greenhouse gas under CAA section 111(d).
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\43\ See ``Phosphate Fertilizer Plants; Final Guideline Document
Availability,'' 42 Fed. Reg. 12,022 (Mar. 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980);
``Standards of Performance for New Stationary Sources and Guidelines
for Control of Existing Sources: Municipal Solid Waste Landfills,
Final Rule,'' 61 FR 9905 (Mar. 12, 1996).
\44\ See, e.g., ``Standards of Performance for New Stationary
Sources and Emission Guidelines for Existing Sources: Sewage Sludge
Incineration Units, Final Rule,'' 76 FR 15,372 (Mar. 21, 2011).
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The EPA's previous CAA section 111(d) actions were necessarily
geared toward the pollutants and industries regulated. Similarly, in
this proposed rulemaking, in defining CAA section 111(d) emission
guidelines for the states and determining the BSER, the EPA believes
that taking into account the particular characteristics of carbon
pollution, the interconnected nature of the power sector and the manner
in which EGUs are currently operated is warranted. Specifically, the
operators themselves treat increments of generation as interchangeable
between and among sources in a way that creates options for relying on
varying utilization levels, lowering carbon generation, and reducing
demand as components of the overall method for reducing CO2
emissions. Doing so results in a broader, forward-thinking approach to
the design of programs to yield critical CO2 reductions that
improve the overall power system by lowering the carbon intensity of
power generation, while offering continued reliability and cost-
effectiveness. These opportunities exist in the power sector in ways
that were not relevant or available for other industries for which the
EPA has established CAA section 111(d) emission guidelines.\45\
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\45\ See ``Phosphate Fertilizer Plants; Final Guideline Document
Availability,'' 42 FR 12,022 (Mar. 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980);
``Standards of Performance for New Stationary Sources and Guidelines
for Control of Existing Sources: Municipal Solid Waste Landfills,
Final Rule,'' 61 F R 9905 (Mar. 12, 1996).
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In this action, the EPA is proposing emission guidelines for states
to follow in developing their plans to reduce emissions of
CO2 from the electric power sector.
III. Stakeholder Outreach and Conclusions
A. Stakeholder Outreach
1. The President's Call for Engagement
Following the direction of the Presidential Memorandum to the
Administrator (June 25, 2013),\46\ this proposed rule was developed
after extensive and vigorous outreach to stakeholders and the general
public. The Presidential Memorandum instructed the Administrator to
inaugurate the process for developing standards through direct
engagement with the states and a full range of stakeholders:
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\46\ Presidential Memorandum--Power Sector Carbon Pollution
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
Launch this effort through direct engagement with States, as
they will play a central role in establishing and implementing
standards for existing power plants, and, at the same time, with
leaders in the power sector, labor leaders, non-governmental
organizations, other experts, tribal officials, other stakeholders,
and members of the public, on issues informing the design of the
program.
2. Educating the Public and Stakeholder Outreach
To carry out this stakeholder outreach, the EPA embarked on an
unprecedented pre-proposal outreach effort. From consumer groups to
states to power plant owner/operators to technology innovators, the EPA
sought input from all perspectives.
The EPA began the outreach efforts with a webinar and associated
teleconferences to establish a common understanding of the basic
requirements and process of CAA section 111(d). The August 27, 2013
overview presentation was offered as a webinar for state and tribal
officials, ``Building a Common Understanding: Clean Air Act and
Upcoming Carbon Pollution Guidelines for Existing Power Plants.''
The EPA followed up on the presentation by offering four national
teleconference calls with representatives from states, tribes,
industry, environmental justice organizations, community organizations
and environmental representatives. The teleconferences offered a venue
for stakeholders to ask questions of the EPA about the overview
presentation and for the EPA to gather initial reactions from
stakeholders. Stakeholders and members of the public continued to view
and refer to the overview presentation throughout the outreach process.
By May 2014, the presentation had been viewed more than 5,600 times.
The agency also provided mechanisms for anyone from the public to
provide input during the pre-proposal development of this action. The
EPA set up two user-friendly options to accept input during the pre-
proposal period--email and a web-based form. The EPA has received more
than 2,000 emails offering input into the development of these
guidelines.
These emails and other materials provided to the EPA are posted on
line as part of a non-regulatory docket, EPA Docket ID No. EPA-HQ-OAR-
2014-0020, at www.regulations.gov. All of the documents on which this
proposal is based are available at Docket ID No. EPA-HQ-OAR-2013-0602,
at www.regulations.gov. However, while the information collected
through extensive outreach helped the agency formulate this proposal,
we are not relying on all of the documents, emails, and other
information included in the informational docket that was established
as a part of that outreach effort, nor will the EPA be responding to
specific comments or issues raised during the outreach effort. Rather,
we have included in the docket for this proposal all of the information
we relied on for this action.
The agency has encouraged, organized, and participated in hundreds
of meetings about CAA section 111(d) and reducing carbon pollution from
existing power plants. Attendees at these various meetings have
included states and tribes, members of the public, and representatives
from multiple industries, labor leaders, environmental groups and other
non-governmental organizations. The direct engagement has brought
together a variety of states and stakeholders to discuss a wide range
of issues related to the electricity sector and the development of
emission guidelines under CAA section 111(d). The meetings occurred in
Washington, DC, and at locations across the country. The meetings were
attended by the EPA Regional Administrators, managers and staff and who
are playing or will play key roles in developing and implementing the
rule.
Part of this effort included the agency's holding of 11 public
listening sessions; one national listening session in Washington, DC
and 10 listening sessions in locations in the EPA regional offices
across the country. All of the outreach meetings were designed to
solicit policy ideas, concerns and technical information from
stakeholders about using CAA section 111(d).
This outreach process has produced a wealth of information which
has informed this proposal significantly. The pre-proposal outreach
efforts far exceeded what is required of the agency in the normal
course of a rulemaking process, and the EPA expects that the dialog
with states and stakeholders will continue throughout the process and
even after the rule is finalized. The EPA recognizes the importance of
working with all stakeholders, and in particular with the states, to
ensure a clear and common understanding of the role the
[[Page 34846]]
states will play in addressing carbon pollution from power plants.
3. Public Listening Sessions
More than 3,300 people attended the public listening sessions held
in 11 cities across the country. Holding the listening sessions at the
EPA's regional offices offered thousands of people from different parts
of the country the opportunity to provide input to EPA officials in
accessible venues. In addition to being well located, holding the
sessions in regional offices also allowed the agency to use resources
prudently and enabled a variety of the EPA staff involved in the
development and ultimate implementation of this upcoming rule to attend
and learn from the views expressed.
More than 1,600 people spoke at the 11 listening sessions. Speakers
included Members of Congress, other public officials, industry
representatives, faith-based organizations, unions, environmental
groups, community groups, students, public health groups, energy
groups, academia and concerned citizens. Participants shared a range of
perspectives. Many were concerned by the impacts of climate change on
their health and on future generations, others worried about the impact
of regulations on the economy. Their support for the agency's efforts
varied.
Summaries of these 11 public listening sessions are available at
www.regulations.gov at EPA Docket ID No. EPA-HQ-OAR-2014-0020.
4. State Officials
Since fall 2013, the agency provided multiple opportunities for the
states to inform this proposal. In addition, the EPA organized,
encouraged and attended meetings to discuss multi-state planning
efforts. Because of the interconnectedness of the power sector, and the
fact that electricity generated at power plants crosses state lines,
states, utilities and ratepayers may benefit from states working
together to address the requirements of this rulemaking implementation.
The meetings provided state leaders, including governors, environmental
commissioners, energy officers, public utility commissioners, and air
directors, opportunities to engage with the EPA officials.
Agency officials listened to ideas, concerns and details from
states, including from states with a wide range of experience in
reducing carbon pollution from power plants. The agency has collected
policy papers from states with overarching energy goals and technical
details on the states' electricity sector. The agency has engaged, and
will continue to engage with, all of the 50 states throughout the
rulemaking process.
5. Tribal Officials
The EPA conducted significant outreach to tribes, who are not
required to--but may--develop or adopt Clean Air Act programs. The EPA
is aware of three coal-fired power plants and one natural gas-fired EGU
located in Indian country but is not aware of any EGUs that are owned
or operated by tribal entities.
The EPA conducted outreach to tribal environmental staff and
offered consultation with tribal officials in developing this action.
Because the EPA is aware of tribal interest in this proposed rule, the
EPA offered consultation with tribal officials early in the process of
developing the proposed regulation to permit tribes to have meaningful
and timely input into its development.
The EPA sent consultation letters to 584 tribal leaders. The
letters provided information regarding the EPA's development of
emission guidelines for existing power plants and offered consultation.
None have requested consultation. Tribes were invited to participate in
the national informational webinar held August 27, 2013. In addition, a
consultation/outreach meeting was held on September 9, 2013, with
tribal representatives from some of the 584 tribes. The EPA
representatives also met with tribal environmental staff with the
National Tribal Air Association, by teleconference, on December 19,
2013. In those teleconferences, the EPA provided background information
on the GHG emission guidelines to be developed and a summary of issues
being explored by the agency.
In addition, the EPA held a series of listening sessions prior to
development of this proposed action. Tribes participated in a session
on September 9, 2013 with the state agencies, as well as in a separate
session with tribes on September 26, 2013.
6. Industry Representatives
Agency officials have engaged with industry leaders and
representatives from trade associations in scores of one-on-one and
national meetings. Many meetings occurred at the EPA headquarters and
in the EPA's Regional Offices and some were sponsored by stakeholder
groups. Because the focus of the standard is on the electricity sector,
many of the meetings with industry have been with utilities and
industry representatives directly related to the electricity sector.
The agency has also met with energy industries such as coal and natural
gas interests, as well as companies that offer new technology to
prevent or reduce carbon pollution, including companies that have
expertise in renewable energy and energy efficiency. Other meetings
have been held with representatives of energy intensive industries,
such as the iron and steel and aluminum industries to help understand
the issues related to large industrial users of electricity.
7. Electric Utility Representatives
Agency officials participated in many meetings with utilities and
their associations. The meetings focused on the importance of the
utility industry in reducing carbon emissions from power plants. Power
plant emissions are central to this rulemaking. The EPA encouraged
industry representatives to work with state environmental and energy
officers.
The electric utility representatives included private utilities or
investor owned utilities. Public utilities and cooperative utilities
were also part of in-depth conversations about CAA section 111(d) with
EPA officials.
The conversations included meetings with the EPA headquarters and
Regional offices. State officials were included in many of the
meetings. Meetings with utility associations and groups of utilities
were held with key EPA officials. The meetings covered technical,
policy, and legal topics of interest and utilities expressed a wide
variety of support and concerns about CAA section 111(d).
8. Electricity Grid Operators
The EPA had a number of conversations with the Independent System
Operators and Regional Transmission Organizations (ISOs and RTOs) to
discuss the rule and issues related to grid operations and reliability.
EPA staff met with the ISO/RTO Council on several occasions to collect
their ideas. The EPA Regional Offices also met with the ISOs and RTOs
in their regions. System operators have offered suggestions in using
regional approaches to implement CAA section 111(d) while maintaining
reliable, affordable electricity.
9. Representatives From Non-Governmental Organizations
Agency officials engaged with representatives of environmental
justice organizations during the outreach effort, for example, we
engaged with the National Environmental Justice Advisory Council
members in September 2013. The NEJAC is composed of stakeholders,
including environmental justice leaders and other
[[Page 34847]]
leaders from state and local government and the private sector.
The EPA has also met with a number of environmental groups to
provide their ideas on how to reduce carbon pollution from existing
power plants using section 111(d) of the CAA.
Many environmental organizations discussed the need for reducing
carbon pollution. Meetings were technical, policy and legal in nature
and many groups discussed specific state policies that are already in
place to reduce carbon pollution in the states.
A number of organizations representing religious groups have
reached out to the EPA on several occasions to discuss their concerns
and ideas regarding this rule.
Public health groups discussed the need for protection of
children's health from harmful air pollution. Doctors and health care
providers discussed the link between reducing carbon pollution and air
pollution and public health. Consumer groups representing advocates for
low income electricity customers discussed the need for affordable
electricity. They talked about reducing electricity prices for
consumers through energy efficiency and low cost carbon reductions.
10. Labor
EPA senior officials and staff met with a number of labor union
representatives about reducing carbon pollution using CAA section
111(d). Those unions included: The United Mine Workers of America; the
Sheet Metal, Air, Rail and Transportation Union (SMART); the
International Brotherhood of Boilermakers, Iron Ship Builders,
Blacksmiths, Forgers and Helpers (IBB); United Association of
Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of
the United States and Canada; the International Brotherhood of
Electrical Workers (IBEW): And the Utility Workers Union of America. In
addition, agency leaders met with the Presidents of several unions and
the President of the American Federation of Labor-Congress of
Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters.
EPA officials, when invited, attended meetings sponsored by labor
unions to give presentations and engage in discussions about reducing
carbon pollution using CAA section 111(d). These included meetings
sponsored by the IBB and the IBEW.
B. Key Messages From Stakeholders
Many stakeholders stated that opportunities exist to reduce the
carbon emissions from existing power generation through a wide range of
measures, from measures that are implementable via physical changes at
the source to those that also are implementable across the broader
power generation system. Opinions varied about how broader system
measures could factor into programs to reduce carbon pollution. Some
stakeholders recommended that system-wide measures be allowed for
compliance, but not factored into the carbon improvement goals the EPA
establishes, while others recommended that system-wide measures be
factored into the goals. Among the arguments and information offered by
stakeholders who suggested that states be encouraged to incorporate
system-wide measures into their state plans and that EGU operators be
encouraged to rely on such measures were examples and discussions of
the significant extent to which dispatch, end use energy efficiency and
renewable energy had already proven to be successful strategies for
reducing EGU CO2 emissions. Some state and industry
representatives favored goals that they described as based on measures
implementable only within the facility ``fence line'' (i.e., measures
implementable only at the source). Many stakeholders stated that the
EPA should not require the state plans to impose on the affected EGUs
legal responsibility for the full amount of required CO2
emissions reductions, and instead, the EPA should authorize the state
plans to include requirements on entities other than the affected EGUs
that would have the effect of reducing utilization and, therefore,
emissions from the affected EGUs.
Views on the form and stringency of the goal or guidelines varied.
Some stakeholders preferred a rate-based form of the goal, while others
preferred a mass-based form. In addition, some stakeholders recommended
that the EPA let the states have the flexibility to either choose among
multiple forms of the goals or to set their own goals. With regard to
the stringency of the goal, some stakeholders recommended that the
stringency of the goals vary by state, to account for differences in
state circumstances.
Many stakeholders recognized the value of allowing states
flexibility in implementing the goals the EPA establishes. For example,
states highlighted the importance of the EPA recognizing existing state
and regional programs that address carbon pollution, including market-
based programs, and allowing credit for prior accomplishments in
reducing CO2 emissions. Many states and other stakeholders
noted the importance of the EPA allowing flexibility in compliance
options such that states could use approaches such as demand-side
management to attain the goals.
Many stakeholders recommended that states be allowed to develop
multi-state programs. It was frequently noted that such regional
approaches could offer cost-effective carbon pollution solutions.
There was broad agreement that most states would need more than one
year to develop and submit their complete plans to the EPA. For some
states, more time is necessary because of the state legislative
schedule and/or regulatory process. In some cases, approval of a plan
through a state's legislative or regulatory process could take one year
or more after the plan has already been developed. Additional time
would also allow and encourage multi-state and regional partnerships
and programs.
Many stakeholders also supported flexibility in the timing of
implementation of the state plans and power sector compliance with the
goals in the state plans. Such flexibility, some stakeholders asserted,
would accommodate the diverse GHG mitigation potential of states and
support more cost-effective approaches to achieving CO2
reductions.
During the outreach process, some stakeholders raised general
concerns that the rulemaking could have a negative impact on jobs and
ratepayers. Some stakeholders also expressed concerns about potential
adverse effects on electric system reliability. Some stakeholders were
concerned that meeting the goals could potentially result in stranded
generation assets. To prevent this from occurring, some stakeholders
suggested varying the stringency of standards to account for individual
state circumstances and variation.
The EPA has given stakeholder input careful consideration during
the development of this proposal and, as a result, this proposal
includes features that are intended to be responsive to many
stakeholder concerns.
C. Key Stakeholder Proposals
During the EPA's public outreach in advance of this proposal, a
number of ideas were put forward that are not fully reflected in this
proposal. We invite public comment on these ideas, some of which are
outlined below.
1. Model Rule on Interstate Emissions Credit Trading and Price Ceiling
Some groups thought that the EPA should put forward a model rule
for an interstate emissions credit trading program that could be easily
adopted by states who wanted to use such a
[[Page 34848]]
program for its plan. One group suggested the model rule should include
a provision to allow the state to compensate merchant generators as
well as retail rate payers. Another group specified that the model rule
would also include a ceiling-price called an alternative compliance
payment that would fund state directed clean technology investment.
Facilities that face costs that exceed the ceiling price could opt to
pay into the fund as a way of complying.
2. Equivalency Tests
One group recommended that state programs be allowed to demonstrate
equivalency using one of three tests: Rate-based equivalency via a
demonstration that the state program achieves equivalent or better
carbon intensity for the regulated sector; mass-based equivalency via a
demonstration that the program achieves equal or greater emission
reductions relative to what would be achieved by the federal approach;
or a market price-based equivalency via a demonstration that the
program reflects a carbon price comparable to or greater than the cost-
effectiveness benchmark used by the EPA in designing the program. The
EPA is proposing a way to demonstrate equivalency and that is discussed
in Section VIII of this preamble.
3. Power Plant-Specific Assessment
Other stakeholders suggested that an ``inside the fence'' plant- or
unit-specific assessment linked to the availability of control at the
source such as heat rate improvements should be considered. They
indicated that once plant-specific goals are established based on on-
site CO2 reduction opportunities, the source should have the
flexibility to look ``outside the fence'' for the means to achieve the
goals, including the use of emissions trading, and averaging.
The EPA invites comment on these suggestions.
D. Consideration of the Range of Existing State Policies and Programs
Across the nation, many states and regions have shown strong
leadership in creating and implementing policies and programs that
reduce GHG emissions from the power sector while achieving other
economic, environmental, and energy benefits. Some of these activities,
such as market-based programs and GHG performance standards, directly
require GHG emission reductions from EGUs. Others reduce GHG emissions
by reducing utilization of fossil fuel-fired EGUs through, for example,
renewable portfolio standards (RPS) and energy efficiency resource
standards (EERS), which alter the mix of energy supply and reduce
energy demand. States have developed their policies and programs with
stakeholder input and tailored them to their own circumstances and
priorities. Their leadership and experiences provided the EPA with
important information about best practices to build upon in this
proposed rule. As directed by the Presidential Memorandum, the EPA is,
with this proposal to reduce power plant carbon pollution, building on
actions already underway in states and the power sector.
1. Market-Based Emission Limits
Nine states actively participate in the Regional Greenhouse Gas
Initiative (RGGI), a market-based CO2 emission reduction
program addressing EGUs that was established in 2009.\47\ Through RGGI,
the participating states are implementing coordinated CO2
emission budget trading programs. In aggregate, these programs
establish an overall limit on allowable CO2 emissions from
affected EGUs in the participating states. Participating states issue
CO2 allowances in an amount up to the number of allowances
in each state's annual emission budget. At the end of each three-year
compliance period, affected EGUs must submit CO2 allowances
equal to their reported CO2 emissions. CO2
allowances may be traded among both regulated and non-regulated
parties, creating a market for emission allowances. This market creates
a price signal for CO2 emissions, which factors into the
dispatch of affected EGUs. A price signal for CO2 emissions
also allows sources flexibility to make emission reductions where
reduction costs are lowest, and encourages innovation in developing
emission control strategies.
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\47\ The nine states include Connecticut, Delaware, Maine,
Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and
Vermont.
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Approximately 90 percent of CO2 allowances are
distributed by the RGGI participating states through auction.\48\ From
2009 through 2012, the nine RGGI states invested auction proceeds of
more than $700 million in programs that lower costs for energy
consumers and reduce CO2 emissions.\49\ Through 2012, for
example, the RGGI states invested approximately $460 million of
proceeds into energy efficiency programs.\50\ The participating RGGI
states estimate that those investments are providing benefits to energy
consumers in the region of more than $1.8 billion in lifetime energy
savings.\51\
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\48\ Regional Greenhouse Gas Initiative 2013 Allowance
Allocation http://rggi.org/design/overview/allowance-allocation/2013-allocation.
\49\ Regional Investments of RGGI CO2 Allowance
Proceeds, 2012 (2014), available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
\50\ Of the $707 million in auction proceeds invested by RGGI
participating states through 2012, 65 percent supported end-use
energy efficiency programs. See Regional Greenhouse Gas Initiative,
``Regional Investments of RGGI CO2 Allowance Proceeds,
2012'' (2014). Available at http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf.
\51\ Id.
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Between 2005, when an agreement to implement RGGI was announced,
and 2012, power sector CO2 emissions in the RGGI
participating states fell by more than 40 percent.\52\ RGGI was not the
primary driver for these reductions but the reductions led RGGI-
participating states to later adjust the CO2 emission limits
downward.\53\ In January 2014, the participating states lowered the
overall allowable CO2 emission level in 2014 by 45 percent,
setting a multi-state CO2 emission limit for affected EGUs
of 91 million short tons of CO2 in 2014 and 78 million short
tons of CO2 in 2020, more than 50 percent below 2008
levels.\54\
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\52\ Regional Greenhouse Gas Initiative, Report on Emission
Reduction Efforts of the States Participating in the Regional
Greenhouse Gas Initiative and Recommendations for Guidelines under
Section 111(d) of the Clean Air Act (2013).
\53\ The first three-year control period under RGGI,
establishing CO2 emission limits for EGUs, began on
January 1, 2009.
\54\ RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.pdf.
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Similarly, California established an economy-wide market-based GHG
emissions trading program under the authority of its 2006 Global
Warming Solutions Act, which requires the state to reduce its 2020 GHG
emissions to 1990 levels.\55\ While California's emission trading
program, like its state emission limit, is multi-sector in scope, the
state projects that the emissions trading program and related
complementary measures will reduce power sector GHG emissions to less
than 80 million metric tons of CO2 equivalent by 2025, a 25
percent reduction from 2005 power sector emission levels.\56\ Prior to
the implementation of the emission trading program, California reports
that it reduced CO2 power sector emissions by 16 percent
from 2005 to a 2010-2012
[[Page 34849]]
averaging period, a reduction of 16 million metric tons of
CO2 equivalent.\57\
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\55\ State of California Global Warming Solutions Act of 2006,
Assembly Bill 32, Chapter http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf.
\56\ Preliminary California Air Resources Board analyses, based
in part on CARB 2008 to 2012 Emissions for Mandatory GHG reporting
Summary (2013), cited in Letter to the EPA Administrator, ``States'
Roadmap on Reducing Carbon Pollution,'' December 16, 2013. Available
at http://www.georgetownclimate.org/sites/default/files/EPA_Submission_from_States-FinalCompl.pdf.
\57\ Id.
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2. GHG Performance Standards
Four states, California, New York, Oregon and Washington, have
enacted GHG emission standards that impose enforceable emission limits
on new and/or expanded electric generating units. For example, since
2012, New York requires new or expanded baseload plants that are
greater than 25 Megawatts (MW) to meet an emission rate of either 925
pounds CO2/Megawatt hour (MWh) (based on output) or 120
pounds of CO2/Million British Thermal Units (MMBtu) (based
on input). Similarly, non-baseload plants in New York of at least 25 MW
or larger must meet an emission rate of either 1450 pounds
CO2/MWh (based on output) or 160 pounds of CO2/
MMBtu (based on input).\58\
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\58\ 6 New York Codes, Rules & Regulations. Part 251 (Adopted
June 28, 2012).
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Three states, California, Oregon and Washington, have enacted GHG
emission performance standards that set an emission rate for
electricity purchased by electric utilities. In both Oregon and
Washington, for example, electric utilities may enter into long term
power purchase agreements for baseload power only if the electric
generator supplying the power has a CO2 emission rate of
1,100 pounds of CO2 per MWh or less.\59\
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\59\ OR SB 101 (2000); Washington Revised Code ch.80.80 (2013);
Wash SB 6001 (2007).
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3. Utility Planning Approaches
Two states, Minnesota and Colorado, have worked collaboratively
with their investor-owned utilities to develop multi-pollutant emission
reduction plans on a utility-wide basis. This multi-pollutant,
collaborative approach enables utilities to determine the least cost
way to meet long term and comprehensive energy and environmental goals.
Colorado's Clean Air, Clean Jobs Act of 2010, for example, required
Colorado investor-owned utilities with coal plants to develop a multi-
pollutant plan to meet existing and reasonably foreseeable federal CAA
requirements.\60\ The utilities were not required to adopt a specific
plan set by the state but were, instead, required to work
collaboratively with the Colorado Department of Public Health and
Environmental and Colorado Public Utility Commission to develop an
acceptable plan. Xcel Energy, Colorado's largest investor-owned
utility, submitted a plan that was approved in 2010. With this plan,
Xcel Energy is projected to reduce its CO2 emissions from
generation in Colorado by 28 percent by 2020.\61\
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\60\ Colorado Clean Air, Clean Jobs Act, HB1365.
\61\ Xcel Energy, Colorado Clean Air-Clean Jobs Plan, available
at http://www.xcelenergy.com/Environment/Doing_Our_Part/Clean_Air_Projects/Colorado_Clean_Air_Clean_Jobs_Plan.
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4. Renewable Portfolio Standards
More than 25 states have mandatory renewable portfolio standards
that require retail electricity suppliers to supply a minimum
percentage or amount of their retail electricity load with electricity
generated from eligible sources of renewable energy.\62\ These
standards have been established via utility regulatory commissions,
legislatures and citizen ballots and requirements vary from state to
state. State RPS typically specify the types of renewable energy, or
other energy sources, that qualify for use toward achievement of the
standard, and often allow for the use of qualifying renewable energy
resources located outside of the state. They reduce utilization of
fossil fuel-fired EGUs and, thereby, lead to reductions in GHG
emissions by meeting a portion of the demand for electricity through
renewable or other energy sources.
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\62\ http://www.dsireusa.org/.
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In 2007, the Minnesota legislature amended the state's 2001
renewable energy objective and established a renewable energy standard
(RES) requiring at least 25 percent of all electricity generated or
purchased in Minnesota to come from renewable energy by 2025. The
standard sets requirements and timetables, beginning in 2010, that vary
based on the provider. For example, in 2011, Xcel Energy had a
requirement to generate or purchase 15 percent of its total retail
sales from renewable energy while all other utilities had a target of 7
percent of total retail sales. According to the latest Minnesota
Department of Commerce report to the legislature on progress, all
utilities subject to the standard met it for 2011 and were on track to
meet their 2012 goals.\63\ The 2012 requirement increased to 18 percent
of total retail sales for Xcel Energy and 12 percent for all other
utilities.\64\ In 2013, the Minnesota legislature expanded the RES with
solar incentives and a specific solar energy standard requiring
Minnesota utilities to ensure that at least 1.5 percent of their retail
electricity sales in 2020 come from solar energy.\65\
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\63\ Report to the Minnesota Legislature: Progress on Compliance
By Electric Utilities With The Minnesota Renewable Energy Objective
and the Renewable Energy Standard, Prepared by: The Minnesota
Department of Commerce, Division of Energy Resources January 14,
2013; http://mn.gov/commerce/energy/images/2013RESLegReport.pdf.
\64\ Id.
\65\ Minnesota Statutes 2013, Section 216B.1691, Subdivision 2f.
Solar Energy Standard https://www.revisor.mn.gov/statutes/?id=216b.1691.
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The Oregon Renewable Portfolio Standard (RPS) is another example of
a state requirement for renewables. Originally enacted in 2007, it
requires that all utilities serving Oregon meet a percentage of their
retail electricity needs with qualified renewable resources. Like in
Minnesota, the percentage varies across utilities with the three
largest utilities required to reach five percent from renewable energy
sources starting in 2011, 15 percent in 2015, 20 percent in 2020, and
25 percent in 2025. Other electric utilities in the state are required
to reach levels of five percent or ten percent by 2025, depending on
their size. According to the latest RPS compliance reports submitted by
the largest utilities for the state, each had achieved the five percent
target as of the end of 2012.\66\
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\66\ Eugene Water Electric Board Oregon Renewable Portfolio
Standard 2012 Compliance Report and 2013-2030 Implementation Plan,
June 1, 2013. PacifiCorp's Renewable Portfolio Standard Oregon
Compliance Report for 2012, May 31, 2013. PGE 2012 Renewable
Portfolio Standard Compliance Report, June 1, 2013.
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5. Demand-Side Energy Efficiency Programs
Many electric utilities, third-party administrators, and states
implement demand-side energy efficiency programs to reduce generation
from EGUs by reducing electricity use, including peak demand. When
these programs reduce fossil fuel electricity generation, they also
reduce CO2 emissions. Demand-side energy efficiency programs
use a variety of energy efficiency measures to target a variety of end
uses and are often driven by existing state standards and programs,
such as policies requiring utilities to obtain ``all cost-effective
energy efficiency'' through long-term integrated resource planning
(IRP), renewable portfolio standards (RPS) that include efficiency as a
qualifying resource, energy efficiency resource standards (EERS),
public benefit funds, and other demand-side planning requirements.
The purposes of demand-side energy efficiency programs vary; goals
include to reduce GHG emissions by reducing fossil-fired generation,
help states achieve energy savings goals, save energy and money for
consumers and improve electricity reliability. They are typically
funded through a small fee or surcharge on customer electricity bills,
but can also be funded by other sources, such as from RGGI
CO2 allowance auction proceeds mentioned above.
[[Page 34850]]
Nationally, total spending on electric ratepayer-funded energy
efficiency programs was about $5 billion in 2012.\67\ Based on Lawrence
Berkeley National Laboratory (LBNL) projections, spending is projected
to reach $8.1 billion in 2025.\68\
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\67\ Consortium for Energy Efficiency Annual Industry Report:
2013 State of the Efficiency Program Industry--Budgets, Expenditures
and Impacts, 2014.
\68\ Lawrence Berkeley National Laboratory (LBNL) The Future of
Utility Customer-Funded Energy Efficiency Programs in the United
States: Projected Spending and Savings to 2025 (http://emp.lbl.gov/sites/all/files/lbnl-5803e.pdf).
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Electricity savings from energy efficiency programs are also
growing. In 2011, electricity savings from these programs totaled
approximately 22.9 million MWh, a 22 percent increase from the previous
year.\69\
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\69\ American Council for an Energy Efficient Economy (ACEEE)
2013 State Scorecard http://www.aceee.org/sites/default/files/publications/researchreports/e13k.pdf.
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California has been advancing energy efficiency through utility-run
demand-side energy efficiency programs for decades and considers energy
efficiency ``the bedrock upon which climate policies are built.'' \70\
It requires its investor-owned utilities to meet electricity load
``through all available energy efficiency and demand reduction
resources that are cost-effective, reliable and feasible.'' \71\ The
California Public Utility Commission works with the California Energy
Commission to determine the amount of cost-effective reduction
potential and establishes efficiency targets. A recent energy
efficiency potential study found that, even after years of running
programs, California can still tap ``tens of thousands of GWh in
potential savings . . . over the next decade.'' \72\ Investor-owned
utilities use demand-side energy efficiency programs to achieve their
targets and currently ``save about 3,000 GW per year, enough savings to
power about 600,000 households.'' \73\ Between 2010 and 2011, these
programs are estimated to have reduced CO2 by 3.8 million
tons.\74\
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\70\ December 27, 2013 Letter from Mary D. Nichols, Chairman of
California Air Resources Board, to EPA Administrator Gina McCarthy.
\71\ Cal Pub. Utility Code Sec. 454.5 (a)(9)(C).
\72\ Cited in December 27, 2013 Letter from Mary D. Nichols,
Chairman of California Air Resources Board, to EPA Administrator
Gina McCarthy.
\73\ Id.
\74\ Id.
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In Vermont, for example, the Vermont Legislature and the Vermont
Public Service Board (PSB) established the first statewide ``energy
efficiency utility'' in 1999 to provide energy efficiency services to
residences and businesses throughout the state.\75\ Vermont law
requires that the energy efficiency utility budgets be set at a level
to achieve ``all reasonably available, cost-effective energy
efficiency'' and then specific energy (kWh) and peak demand (kW)
savings levels are negotiated every three years.\76\ In 2013,
Efficiency Vermont, the PSB-appointed energy efficiency utility,
achieved annual savings of 1.66 percent of the state's electricity
sales, at a cost of 4.1 cents per kilowatt[hyphen]hour, lower than the
cost of comparable electric supply in the same year, which was 8.4
cents per kWh.\77\ Efficiency Vermont projects a net lifetime economic
value to Vermont of more than $60 million from the 2013 energy
efficiency investments.\78\
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\75\ State of Vermont Public Service Board, Energy Efficiency
Utility Creation and Structure. http://psb.vermont.gov/utilityindustries/eeu/generalinfo/ creationandstructure.
\76\ Vermont Statute, Title 30: Public Service, 30 V.S.A. Sec.
209 (d)3(B). http://www.leg.state.vt.us/statutes/fullsection.cfm?Title=30&Chapter=005&Section=00209.
\77\ Efficiency Vermont Savings Claim Summary 2013, Reported to
the Vermont Public Service Board and to the Vermont Public Service
Department, 2014, https://www.efficiencyvermont.com/docs/about_efficiency_vermont/annual_summaries/2013_savingsclaim_summary.pdf.
\78\ Id.
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6. Energy Efficiency Resource Standards
More than 20 states have energy efficiency resource standards
(EERS) that require utilities to save a certain amount of energy each
year or cumulatively.\79\ They are typically multi-year requirements
expressed as a percentage of annual retail electricity sales or as
specific electricity savings amounts over a long term period relative
to a baseline of retail sales. Over the compliance period, an EERS
reduces fossil fuel-fired EGU generation through reductions in
electricity demand, thereby reducing CO2 emissions from the
power sector.
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\79\ State Energy Efficiency Resource Standards: Policy Design,
Status, and Impacts, DC Steinberg, O. Zinaman, NREL Technical Report
NREL/TP-6A20-61023, April 2014.
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In Arizona, for example, the Arizona Corporation Commission (ACC)
adopted rules in 2010 requiring all investor-owned utilities to achieve
22 percent cumulative electricity savings by 2020, making it one of the
highest standards in the nation.\80\ The rule required utilities to
achieve 1.25 percent electricity savings in 2011 compared to
electricity sales in the previous year, ramping up the savings each
year until 2020 according to a designated timetable.\81\ In 2012, for
example, investor-owned utilities were required to achieve energy
savings equivalent to 1.75 percent of the 2011 sales, leading to a
cumulative savings requirement of 3 percent by the end of 2012 (an
average of 1.5% annually over the 2 year period).\82\ Utilities can
meet the energy savings requirements through a variety of means,
including cost-effective energy efficiency programs, as well as load
management and demand response programs.\83\ Arizona Public Service
Company (APS), the largest utility in Arizona, achieved cumulative
energy savings equivalent to 3.2 percent of retail sales from 2011 to
2012, exceeding the 3 percent savings target, and reported a net
benefit to consumers of more than $200 million for the year 2012
alone.\84\
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\80\ Arizona Corporation Commission, Docket RE-OOOOOC-09-0427,
August 2010. Available at http://images.edocket.azcc.gov/docketpdf/0000116125.pdf.
\81\ Id.
\82\ Arizona Corporation Commission, Docket RE-OOOOOC-09-0427,
August 2010. Available at http://images.edocket.azcc.gov/docketpdf/0000116125.pdf.
\83\ Id.
\84\ Arizona Public Service Company 2012 Demand Side Management
Annual Progress Report, March 1, 2013 Web site, http://www.aps.com/en/ourcompany/aboutus/energyefficiency/Pages/home.aspx.
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E. Conclusions
States have taken a leadership role in mitigating GHG emissions and
have demonstrated the potential for national application of a number of
approaches. Throughout the development of this proposed rule, the EPA
considered the states' experiences and lessons learned regarding the
design and implementation of successful GHG mitigation programs. The
agency also fully considered input from stakeholders during the
development of this proposed rulemaking.
Considering all input from stakeholders, the agency recognizes that
the most cost-effective approach to reducing GHG emissions from the
power sector under CAA section 111(d) is to follow the lead of numerous
states and not only to identify improvements in the efficiency of
fossil fuel-fired EGUs as a component of the BSER, but also include in
the BSER determination the EGU-emissions-reduction opportunities that
states have already demonstrated to be successful in relying on lower-
and zero-emitting generation and reduced electricity demand.
CAA section 111(d) sets up a partnership between the EPA and the
states. In the context of that partnership, the EPA recognizes the
importance of each state having the flexibility to design a cost-
effective program tailored to its own specific circumstances. The
agency also recognizes, as many states
[[Page 34851]]
have, the value of regional planning in designing approaches to achieve
cost-effective GHG reductions. To support state flexibility and
encourage multi-state coordination in the development of multi-state
and regional programs and policies, the EPA recognizes that flexibility
in both the timing of plan submittal and the timing of CO2
emission reductions will be necessary.
IV. Rule Requirements and Legal Basis
A. Summary of Rule Requirements
The EPA is proposing emission guidelines for each state to use in
developing plans to address greenhouse gas emissions from existing
fossil fuel-fired electric generating units. The emission guidelines
are based on the EPA's determination of the ``best system of emission
reduction . . . adequately demonstrated'' (BSER) and include state-
specific goals, general approvability criteria for state plans,
requirements for state plan components, and requirements for the
process and timing for state plan submittal and compliance.
Under CAA section 111(d), the states must establish standards of
performance that reflect the degree of emission limitation achievable
through the application of the ``best system of emission reduction''
that, taking into account the cost of achieving such reduction and any
non-air quality health and environmental impact and energy
requirements, the Administrator determines has been adequately
demonstrated. Consistent with CAA section 111(d), the EPA is proposing
state-specific goals that reflect the EPA's calculation of the BSER.
Under CAA section 111(d), each state must develop, adopt, and then
submit its plan to the EPA. To do so, the state would determine, and
include in its plan, an emission performance level that is equivalent
to the state-specific CO2 goal in the emission guidelines.
As part of determining this level, the state would decide whether to
adopt the rate-based form of the goal established by the EPA or
translate the rate-based goal to a mass-based goal. The state would
then establish a standard of performance or set of standards of
performance (known as emission standards under the existing CAA section
111(d) framework regulations), along with implementing and enforcing
measures, that will achieve a level of emission performance that equals
or exceeds the level specified in the state plan.
The EPA is proposing to determine the BSER as the combination of
emission rate improvements and limitations on overall emissions at
affected EGUs that can be accomplished through any combination of one
or more measures from the following four sets of measures or building
blocks:
1. Reducing the carbon intensity of generation at individual
affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs
in the amount that results from substituting generation at those EGUs
with generation from less carbon-intensive affected EGUs (including
natural gas combined cycle (NGCC) units that are under construction).
3. Reducing emissions from affected EGUs in the amount that results
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
4. Reducing emissions from affected EGUs in the amount that results
from the use of demand-side energy efficiency that reduces the amount
of generation required.
The EPA has reviewed information about the current and recent
performance of affected EGUs and states' implementation of programs
that reduce CO2 emissions from these sources. Based on our
analysis of that information, the proposed state goals reflect the
following stringency of application of the measures in each of the
building blocks: Block 1, improving average heat rate of coal-fired
steam EGUs by six percent; block 2, displacing coal-fired steam and
oil/gas-fired steam generation in each state by increasing generation
from existing NGCC capacity in that state toward a 70 percent target
utilization rate; block 3, including the projected amounts of
generation achievable by completing all nuclear units currently under
construction, avoiding retirement of about six percent of existing
nuclear capacity, and increasing renewable electric generating capacity
over time through the use of state-level renewable generation targets
consistent with renewable generation portfolio standards that have been
established by states in the same region; and block 4, increasing state
demand-side energy efficiency efforts to reach 1.5 percent annual
electricity savings in the 2020-2029 period.
Based on the EPA's application of the BSER to each state, the EPA
is proposing to establish, as part of the emission guidelines, state-
specific goals, expressed as average emission rates for fossil fuel-
fired EGUs. Each state's goals comprise the EPA's determination of the
emission limitation achievable through application of the BSER in that
state. For each state, the EPA is proposing an interim goal for the
phase-in period from 2020 to 2029 and the final goal that applies
beginning in 2030. The proposed goals for each state are listed in
Section VII, below. The EPA is proposing that measures that a state
takes after the date of this proposal, and that result in
CO2 emission reductions during the plan period, would apply
toward achievement of the state's CO2 goal.
The EPA is further proposing, as part of the plan guidelines,
timetables for states to submit their plans. The agency expects to
finalize this rulemaking by June 2015, and we are proposing to require
that each state submit its plan to the EPA by June 30, 2016. However,
if a state needs additional time to submit a complete plan, the state
must submit an initial plan by June 30, 2016, that documents the
reasons why more time is needed to submit a complete plan and includes
commitments to take concrete steps that will ensure that the state will
submit a complete plan by June 30, 2017, or June 30, 2018, as
appropriate. If such a state is developing a plan limited in
geographical scope to the individual state, then the state would have
until June 30, 2017, to submit a complete plan. A state that is
developing a plan that includes a multi-state approach would have until
June 30, 2018, to submit a complete plan.
The EPA is further proposing, as part of the emission guidelines,
to allow states the option of translating the EPA-determined goal,
which will be rate-based, to a mass-based goal. For states
participating in a multi-state approach, the individual state
performance goals in the emission guidelines would be replaced with an
equivalent multi-state performance goal. The EPA is also proposing that
in their plans, whether single state or multi-state, states may not
adjust the stringency of the goals set by the EPA.
Under CAA section 111(d)(1) and the implementing regulations, with
the state emission performance level in place, the state must adopt a
state plan that establishes a standard of performance or set of
standards of performance, along with implementing and enforcing
measures, that will achieve that emission performance level. The EPA is
further proposing, as part of the guidelines, to authorize the state to
submit either of two types of measures to achieve the performance
level: (1) A set of measures that we refer to as ``portfolio''
measures, which include a combination of emission limitations that
apply directly to the affected sources and other measures that have the
effect of limiting generation by, and therefore emissions from, the
affected sources; or (2) solely emission limitations that apply
directly to the affected sources.
[[Page 34852]]
The EPA is also proposing, as part of the plan guidelines, that a
complete state plan include the following twelve components:
Identification of affected entities
Description of plan approach and geographic scope
Identification of state emission performance level
Demonstration that plan is projected to achieve emission
performance level
Identification of emissions standards
Demonstration that each emissions standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable
Identification of monitoring, reporting, and recordkeeping
requirements
Description of state reporting
Identification of milestones
Identification of backstop measures
Certification of hearing on state plan
Supporting material
The EPA is also proposing, as part of its emission guidelines, that
plan approvability be based on four general criteria: (1) Enforceable
measures that reduce EGU CO2 emissions; (2) projected
achievement of emission performance equivalent to the goals established
by the EPA, on a timeline equivalent to that in the emission
guidelines; (3) quantifiable and verifiable emission reductions; and
(4) a process for reporting on plan implementation, progress toward
achieving CO2 goals, and implementation of corrective
actions, if necessary.
The EPA is also proposing, as part of its plan guidelines,
requirements for the process and timing for demonstrating achievement
of the required emission performance level, including performance and
emission milestones. The proposed option would require each state to
achieve its ultimate CO2 emission performance level by 2030
and, in addition, provide an initial, phase-in compliance period of up
to 10 years, from 2020 up to 2029, for a state and/or other responsible
parties to comply with the emission performance level in the state
plan. A state would need to meet its interim 2020-2029 CO2
emission performance level on average over the 10-year phase-in
compliance period, achieve its final CO2 emission
performance level by 2030, and maintain it thereafter.
If a state with affected EGUs does not submit a plan or if the EPA
does not approve a state's plan, then under CAA section 111(d)(2)(A),
the EPA must establish a plan for that state. A state that has no
affected EGUs must document this in a formal letter submitted to the
EPA by June 30, 2016. In the case of a tribe that has one or more
affected EGUs in its area of Indian country,\85\ the tribe would have
the opportunity, but not the obligation, to establish a CO2
emission performance standard and a CAA section 111(d) plan for its
area of Indian country. If it determines that such a plan is necessary
or appropriate, the EPA has the responsibility to establish CAA section
111(d) plans for areas of Indian country where affected sources are
located unless a tribe on whose lands an affected source (or sources)
is located seeks and obtains authority from the EPA to establish a plan
itself, pursuant to the Tribal Authority Rule.
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\85\ The EPA is aware of at least four affected EGUs located in
Indian country: Two on Navajo lands, the Navajo Generating Station
and the Four Corners Generating Station; one on Ute lands, the
Bonanza Generating Station; and one on Fort Mojave lands, the South
Point Energy Center. The affected EGUs at the first three plants are
coal-fired EGUs. The fourth affected EGU is an NGCC facility.
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B. Summary of Legal Basis
This proposed action is consistent with the requirements of CAA
section 111(d) and the implementing regulations. As an initial matter,
the EPA reasonably interprets the provisions identifying which air
pollutants are covered under CAA section 111(d) to authorize the EPA to
regulate CO2 from fossil fuel-fired EGUs. In addition, the
EPA recognizes that CAA section 111(d) applies to sources that, if they
were new sources, would be covered under a CAA section 111(b) rule. The
EPA intends to complete two CAA section 111(b) rulemakings regulating
CO2 from new fossil fuel-fired EGUs and from modified and
reconstructed fossil fuel-fired EGUs before it finalizes this
rulemaking, and either of those section 111(b) rulemakings will provide
the requisite predicate for this rulemaking.
A key step in promulgating requirements under CAA section 111(d) is
determining the ``best system of emission reduction . . . adequately
demonstrated'' (BSER). In promulgating the implementing regulations,
the EPA explicitly stated that it is authorized to determine the BSER;
\86\ accordingly, in this rulemaking, the EPA is determining the BSER.
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\86\ The EPA is not re-opening that interpretation in this
rulemaking.
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The EPA is proposing two alternative BSER for fossil fuel-fired
EGUs, each of which is based on methods that have already been employed
for reducing emissions of air pollutants, including, in some cases,
CO2, from these sources. The first identifies the
combination of the four building blocks as the BSER. These include
operational improvements and equipment upgrades that the coal-fired
steam-generating EGUs in the state may undertake to improve their heat
rate (building block 1) and increases in, or retention of, zero- or
low-emitting generation, as well as measures to reduce demand for
generation, all of which, taken together, displace, or avoid the need
for, generation from the affected EGUs (building blocks 2, 3, and 4).
All of these measures are components of a ``system of emission
reduction'' for the affected EGUs because they either improve the
carbon intensity of the affected EGUs in generating electricity or,
because of the integrated nature of the electricity system and the
fungibility of electricity, they displace or avoid the need for
generation from those sources and thereby reduce the emissions from
those sources. Moreover, those measures may be undertaken by the
affected EGUs themselves and, in the case of building blocks 2, 3, and
4, they may be required by the states.
Further, these measures meet the criteria in CAA section 111(a)(1)
and the caselaw as the ``best'' system of emission reduction because,
among other things, they achieve the appropriate level of reductions,
they are of reasonable cost, and they encourage technological
development that is important to achieving further emission reductions.
Moreover, the measures in each of the building blocks are ``adequately
demonstrated'' because they are each well-established in numerous
states, and many of them have already been relied on to reduce GHGs and
other air pollutants from fossil fuel-fired EGUs. It should be
emphasized that these measures are consistent with current trends in
the electricity sector.
For the alternative approach for the BSER, the EPA is identifying
the ``system of emission reduction'' as including, in addition to
building block 1, the reduction of affected fossil fuel-fired EGUs'
mass emissions achievable through reductions in generation of specified
amounts from those EGUs. Under this approach, the measures in building
blocks 2, 3, and 4 would not be components of the system of emission
reduction, but instead would serve as bases for quantifying the
reduction in emissions resulting from the reduction in generation at
affected EGUs. In light of the available sources of replacement
generation through the measures in the building blocks, this approach
would also meet the criteria for being the ``best'' system that is
``adequately demonstrated'' because of the emission reductions it would
[[Page 34853]]
achieve, its reasonable cost, and its promotion of technological
development, as well as the fact that the reliability of the
electricity system would be maintained.
After determining the BSER, the EPA is authorized under the
implementing regulations, as an integral component to setting emission
guidelines, to apply the BSER and determine the resulting emission
limitation. The EPA is proposing to apply the BSER to the affected EGUs
on a statewide basis. In this rulemaking, the EPA terms the resulting
emission limitation the state goal.
With the promulgation of the emission guidelines, each state must
develop a plan to achieve an emission performance level that
corresponds to the state goal. The state plans must establish standards
of performance for the affected EGUs and include measures that
implement and enforce those standards. Based on requests from
stakeholders, the EPA is proposing that states be authorized to submit
state plans that do not impose legal responsibility on the affected
EGUs for the entirety of the emission performance level, but instead,
by adopting what this preamble refers to as a ``portfolio approach,''
impose requirements on other affected entities (e.g., renewable energy
and demand-side energy efficiency measures) that would reduce
CO2 emissions from the affected EGUs.
It should be noted that an important aspect of the BSER for
affected EGUs is that the EPA is proposing to apply it on a statewide
basis. The statewide approach also underlies the required emission
performance level, which, as noted, is based on the application of the
BSER to a state's affected EGUs, and which the suite of measures in the
state plan, including the emission standards for the affected EGUs,
must achieve overall. The state has flexibility in assigning the
emission performance obligations to its affected EGUs, in the form of
standards of performance--and, for the portfolio approach, in imposing
requirements on other entities--as long as, again, the required
emission performance level is met.
This state-wide approach both harnesses the efficiencies of
emission reduction opportunities in the interconnected electricity
system and is fully consistent with the principles of federalism that
underlie the Clean Air Act generally and CAA section 111(d)
particularly. That is, this provision achieves the emission performance
requirements through the vehicle of a state plan, and provides each
state significant flexibility to take local circumstances and state
policy goals into account in determining how to reduce emissions from
its affected sources, as long as the plan meets minimum federal
requirements. This state-wide approach, and the standards of
performance for the affected EGUs that the states will establish
through the state-plan process, are consistent with the applicable CAA
section 111 provisions.
A state has discretion in determining the measures in its plans.
The state may adopt measures that assure the achievement of the
required emission performance level, and is not limited to the measures
that the EPA identifies as part of the BSER. By the same token, the
affected EGUs, to comply with the applicable standards of performance
in the state plan, may rely on any efficacious means of emission
reduction, regardless of whether the EPA identifies those measures as
part of the BSER.
In this rulemaking, the EPA proposes reasonable deadlines for state
plan submission and the EPA's action. The proposed deadline for the
EPA's action on state plan submittals varies from that in the
implementing regulations, and the EPA is proposing to revise that
provision in the regulations accordingly. Under CAA section 111(d)(2),
the state plans must be ``satisfactory'' for the EPA to approve them,
and in this rulemaking, the EPA is proposing the criteria that the
state plans must meet under that requirement.
The EPA discusses its legal interpretation in more detail in other
parts of this preamble and discusses certain issues in more detail in
the Legal Memorandum included in the docket for this rulemaking. The
EPA solicits comment on all aspects of its legal interpretations,
including the discussion in the Legal Memorandum.
V. Authority To Regulate Carbon Dioxide and EGUs, Affected Sources,
Treatment of Categories
A. Authority To Regulate Carbon Dioxide
The EPA has the authority to regulate, under CAA section 111(d),
CO2 emissions from EGUs, under the Agency's construction of
the ambiguous provisions in CAA section 111(d)(1)(A)(i) that identify
the air pollutants subject to CAA section 111(d). The ambiguities stem
from apparent drafting errors that occurred during enactment of the
1990 CAA Amendments, which revised section 111(d).
During the 1990 CAA Amendments, the House of Representatives and
the Senate each passed an amendment to CAA section 111(d)(1)(A)(i). The
two amendments differed from each other, and were not reconciled during
the Conference Committee and, as a result, both were enacted into law.
As amended by the Senate, the pertinent language of CAA section
111(d)(1) would exclude the regulation of any pollutant which is
``included on a list published under [CAA section] 112(b).'' \87\ As
amended by the House, the pertinent language in CAA section 111(d)(1)
would exclude the regulation of any pollutant which is ``emitted from a
source category which is regulated under section 112.'' \88\ The two
versions conflict with each other and thus are ambiguous. Under these
circumstances, the EPA may reasonably construe the provision to
authorize the regulation of GHGs under CAA section 111(d).
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\87\ Public Law 101-549, Sec. 302(a), 104 Stat. at 2574 (Nov.
15, 1990).
\88\ Public Law 101-549, Sec. 108(g), 104 Stat. at 2467 (Nov.
15, 1990).
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It should be noted that the U.S. Supreme Court's holding in
American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38
(2011), that ``the Clean Air Act and the EPA actions it authorizes
displace any federal common law right to seek abatement of carbon-
dioxide emissions from fossil fuel-fired power plants'' was premised on
the Court's understanding that CAA section 111, including CAA section
111(d), applies to carbon dioxide emissions from those sources.
We discuss this issue in more detail in the Legal Memorandum.
B. Authority To Regulate EGUs
Before the EPA finalizes this CAA section 111(d) rule, the EPA will
finalize a CAA section 111(b) rulemaking regulating CO2
emissions from new EGUs, which will provide the requisite predicate for
applicability of CAA section 111(d).
CAA section 111(d)(1) requires the EPA to promulgate regulations
under which states must submit state plans regulating ``any existing
source'' of certain pollutants ``to which a standard of performance
would apply if such existing source were a new source.'' A ``new
source'' is ``any stationary source, the construction or modification
of which is commenced after the publication of regulations (or, if
earlier, proposed regulations) prescribing a standard of performance
under [CAA section 111] which will be applicable to such source.'' It
should be noted that these provisions make clear that a ``new source''
includes one that undertakes either new construction or a modification.
It should also be noted
[[Page 34854]]
that the EPA's implementing regulations define ``construction'' to
include ``reconstruction,'' which the implementing regulations go on to
define as the replacement of components of an existing facility to an
extent that (i) the fixed capital cost of the new components exceeds 50
percent of the fixed capital cost that would be required to construct a
comparable entirely new facility, and (ii) it is technologically and
economically feasible to meet the applicable standards.
Under CAA section 111(d)(1), in order for existing sources to
become subject to that provision, the EPA must promulgate standards of
performance under CAA section 111(b) to which, if the existing sources
were new sources, they would be subject. Those standards of performance
may include ones for sources that undertake new construction,
modifications, or reconstructions.
The EPA is in the process of promulgating two rulemakings under CAA
section 111(b) for CO2 emissions from affected sources. The
EPA proposed the first, which applies to affected sources undertaking
new constructions, by notice dated January 8, 2014, which we refer to
as the January 2014 Proposal. The EPA is proposing the second, which
applies to affected sources undertaking modifications or
reconstructions, concurrently with this CAA section 111(d) proposal.
The EPA will complete one or both of these CAA section 111(b)
rulemakings before or concurrently with this CAA section 111(d)
rulemaking, which will provide the requisite predicate for
applicability of CAA section 111(d).\89\
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\89\ In the past, the EPA has issued standards of performance
under section 111(b) and emission guidelines under section 111(d)
simultaneously. See ``Standards of Performance for new Stationary
Sources and Guidelines for Control of Existing Sources: Municipal
Solid Waste Landfills--Final Rule,'' 61 FR 9905 (March 12, 1996).
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C. Affected Sources
The EPA is proposing that, for the emission guidelines, an affected
EGU is any fossil fuel-fired EGU that was in operation or had commenced
construction as of January 8, 2014, and is therefore an ``existing
source'' for purposes of CAA section 111, and that in all other
respects would meet the applicability criteria for coverage under the
proposed GHG standards for new fossil fuel-fired EGUs (79 FR 1430;
January 8, 2014).
The January 8, 2014 proposed GHG standards for new EGUs generally
define an affected EGU as any boiler, integrated gasification combined
cycle (IGCC), or combustion turbine (in either simple cycle or combined
cycle configuration) that (1) is capable of combusting at least 250
million Btu per hour; (2) combusts fossil fuel for more than 10 percent
of its total annual heat input (stationary combustion turbines have an
additional criteria that they combust over 90 percent natural gas); (3)
sells the greater of 219,000 MWh per year and one-third of its
potential electrical output to a utility distribution system; and (4)
was not in operation or under construction as of January 8, 2014 (the
date the proposed GHG standards of performance for new EGUs were
published in the Federal Register). The minimum fossil fuel consumption
condition applies over any consecutive three-year period (or as long as
the unit has been in operation, if less). The minimum electricity sales
condition applies on an annual basis for boilers and IGCC facilities
and over rolling three-year periods for combustion turbines (or as long
as the unit has been in operation, if less).
The rationale for this proposal concerning applicability is the
same as that for the January 8, 2014 proposal, sections V.A-B. See 79
FR at 1,459/1-1,461/2. We incorporate that discussion by reference
here.
D. Implications for Tribes and U.S. Territories
As noted in Section II.D of this preamble, although affected EGUs
located in Indian country operate as part of the interconnected system
of electricity production and distribution, affected EGUs located in
Indian country within a state's borders would not be encompassed within
the state's CAA section 111(d) plan. The EPA is aware of four
potentially affected power plants located in Indian country: The South
Point Energy Center, on Fort Mojave tribal lands within Arizona; the
Navajo Generating Station, on Navajo tribal lands within Arizona; the
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and
the Bonanza Power Plant, on Ute tribal lands within Utah. The South
Point facility is an NGCC power plant, and the Navajo, Four Corners,
and Bonanza facilities are coal-fired power plants. The operators and
co-owners of these four facilities include investor-owned utilities,
cooperative utilities, public power agencies, and independent power
producers, most of which also co-own potentially affected EGUs within
state jurisdictions. We are not aware of any potentially affected EGUs
that are owned or operated by tribal entities. If it determines that
such a plan is necessary or appropriate, the EPA has the responsibility
to establish CAA section 111(d) plans for areas of Indian country where
affected sources are located unless a tribe on whose lands an affected
source (or sources) is located seeks and obtains authority from the EPA
to establish a plan itself, pursuant to the Tribal Authority Rule.\90\
The EPA intends to publish a supplemental proposal to establish
emission performance goals (if it determines that such action is
necessary or appropriate) covering the four potentially affected power
plants identified above, as well as any subsequently identified
similarly situated power plants, and also to proposed goals for U.S.
territories with affected EGUs. The EPA intends to take final action on
that proposal by June 2015. If a tribe does seek and obtain the
necessary authority to establish a plan itself, it is the EPA's
intention that the tribe would have flexibility to develop a plan
tailored to its circumstances, in the same manner as a state, to meet
CO2 emission performance goals that would be established by
the EPA based on application of the BSER to that area of Indian
country. The EPA is aware of actions that have been taken or are being
taken by some sources in tribal areas or territories and will be
mindful of these actions in considering establishment of a plan.
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\90\ See 40 CFR 49.1 to 49.11.
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The EPA invites comment on whether a tribe wishing to develop and
implement a CAA section 111(d) plan should have the option of including
the EGUs located in its area of Indian country in a multi-
jurisdictional plan with one or more states (i.e., treating the tribal
lands as an additional state).
If the EPA develops one or more CAA section 111(d) federal plans
for areas of Indian country with affected EGUs, we are likewise
currently considering doing so on a multi-jurisdictional basis in
coordination with nearby states developing section 111(d) state plans.
The EPA solicits comment on such an approach for a federal plan.
At this time, the EPA is not proposing CO2 emission
performance goals for areas of Indian country containing potentially
affected EGUs. We do plan to establish such goals in the future, to be
addressed through either tribal or federal plans, as discussed above.
The EPA notes that some present and planned actions being taken to
reduce criteria pollutants from EGUs in Indian country will result in
significant CO2 emission reductions relative to emissions in
the 2012 baseline period used in computing the state CO2
[[Page 34855]]
performance goals in this proposal.\91\ We invite comment on how the
BSER should be applied to potentially affected EGUs in Indian country.
We particularly invite comment on data sources for setting renewable
energy and demand-side energy efficiency targets.
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\91\ For example, a plan currently being implemented at the Four
Corners plant to satisfy regional haze requirements calls for
reduction of NOx emissions to be achieved in part by shutting down a
portion of the plant's generating capacity, and a similar plan has
been proposed for the Navajo plant. See 78 FR 62509 (October 22,
2013).
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The state-specific goals that the EPA is proposing are based on the
collection of affected EGUs located within that state. In setting goals
specific to an area of Indian country, the EPA proposes to base the
goals on the collection of affected EGUs located within that area of
Indian country. We request comment on this approach.
E. Combined Categories and Codification in the Code of Federal
Regulations
In this rulemaking, the EPA is soliciting comment on combining the
two existing categories for the affected EGUs into a single category
for purposes of facilitating emission trading among sources in both
categories. The EPA is also proposing codifying all of the proposed
requirements for the affected EGUs in a new subpart UUUU of 40 CFR part
60.
As discussed in the January 8, 2014 proposal for the CAA section
111(b) standards for GHG emissions from EGUs, in 1971 the EPA listed
fossil fuel-fired steam generating boilers as a new category subject to
section 111 rulemaking, and in 1979 the EPA listed fossil fuel-fired
combustion turbines as a new category subject to the CAA section 111
rulemaking. In the ensuing years, the EPA has promulgated standards of
performance for the two categories, and codified those standards, at
various times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. In the
2014 proposal, the EPA proposed separate standards of performance for
sources in the two categories and proposed codifying the standards in
the same Da and KKKK subparts that currently contain the standards of
performance for conventional pollutants from those sources. In
addition, the EPA co-proposed combining the two categories into a
single category solely for purposes of the CO2 emissions
from new construction of affected EGUs, and codifying the proposed
requirements in a new 40 CFR part 60 subpart TTTT. The EPA solicited
comment on whether combining the categories for new sources is
necessary in order to combine the categories for existing sources.
In the present rulemaking, the EPA is proposing emission guidelines
for the two categories and is soliciting comment on combining the two
categories into a single category for purposes of the CO2
emissions from existing affected EGUs. The EPA solicits comment on
whether combining the two categories would offer additional
flexibility, for example, by facilitating implementation of
CO2 mitigation measures, such as shifting generation from
higher to lower-carbon intensity generation among existing sources
(e.g., shifting from boilers to NGCC units) or facilitating emissions
trading among sources. Because the two categories are pre-existing and
the EPA would not be subjecting any additional sources to regulation,
the combined category would not be considered a new category that the
EPA must list under CAA section 111(b)(1)(A). As a result, this
proposal does not list a new category under section 111(a)(1)(A), nor
does this proposal revise either of the two source categories--steam-
generating boilers and combustion turbines--that the EPA has already
listed under that provision. Thus, the EPA would not be required to
make a finding that the combined category causes or contributes
significantly to air pollution which may reasonably be anticipated to
endanger public health or welfare.
In addition, the EPA is proposing to create a new subpart UUUU and
to include all GHG emission guidelines for the affected sources--
utility boilers and IGCC units as well as natural gas-fired stationary
combustion turbines--in that newly created subpart. We believe that
combining the emission guidelines for affected sources into a new
subpart UUUU is appropriate because the emission guidelines the EPA is
establishing do not vary by type of source. Accordingly, the EPA is not
proposing to codify any of the requirements of this rulemaking in
subparts Da or KKKK.
VI. Building Blocks for Setting State Goals and the Best System of
Emission Reduction
A. Introduction
Based on the experiences of states and the industry and the EPA's
outreach with stakeholders as described above, the EPA has identified
multiple measures currently in use for achieving CO2
emission reductions from existing fossil fuel-fired EGUs. For purposes
of determining the ``best system of emission reduction . . . adequately
demonstrated'' (BSER) and developing state emission performance goals,
we have screened the measures and have found that they support two
alternative formulations for the BSER. We are grouping the measures
that we are proposing to consider further at this time into four
categories, which we call ``building blocks.'' We provide an overview
of these building blocks in Section VI.B and more detailed discussion
of each block in Section VI.C. In Section VI.D we discuss possible
combinations of the building blocks, and in Section VI.E, we explain
why as a legal matter all four building blocks, taken together, support
the BSER, which in turn serves as the basis for the standards of
performance that the states must include in their state plans, as CAA
section 111(d) requires.
As discussed in Section III of this preamble, we are mindful of
numerous and varied stakeholder concerns, including the need to achieve
meaningful CO2 emission reductions at the affected
facilities and to recognize and take advantage of the progress already
made by existing programs. Like stakeholders, we are attentive to the
need to maintain electricity system reliability and to minimize adverse
impacts on electricity and fuel prices and on assets that have already
been improved by installation of controls for other kinds of pollution.
Many of these considerations align with our approach to determining the
BSER, as discussed more in Section VII, and we consider several of
these to be key principles in this application. As discussed in
Sections VII and VIII, we acknowledge and appreciate the advantages of
allowing and promoting flexibility for states in crafting their
programs. We recognize the knowledge that states have about their
specific situations and their ability to evaluate and leverage existing
and new capacity and programs to ultimately reduce EGU CO2
emissions.
Similarly, we recognize and appreciate that states operate with
differing circumstances and policy preferences. For example, states
have differing access to specific fuel types, and the variety of types
of EGUs operating in different states is broad and significant. States
are part of assorted EGU dispatch systems and vary in the amounts of
electricity that they import and export. For these reasons, we also
recognize and appreciate the value in allowing and promoting multi-
state reduction strategies. Some states already participate in a multi-
state program that reduces CO2 emissions, the RGGI, and we
have noted the success of that program for those states.
[[Page 34856]]
Another key consideration in determining the BSER, as discussed
more in the following sections, is the relationship between the timing
of measures and their effectiveness in limiting emissions. For example,
actions that can occur in the near term, such as improvements to
individual EGU heat rates, may fail to achieve the cumulative emission
reductions that sustained implementation of other actions, such as
demand-side energy efficiency programs, may achieve over time.
B. Building Blocks for the Best System of Emission Reduction
This subsection summarizes the EPA's analytic approach to
determining the best system of emission reduction (BSER) for
CO2 emissions from existing EGUs. Later subsections discuss
particular measures and how they form the basis of the BSER.\92\
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\92\ The EPA is aware of the potential that one or more
facilities involved in programs mentioned or relied on in this
proposal may have received some form of assistance under the Energy
Policy Act of 2005 (EPAct). Section 402 (i) of the EPAct (codified
at 42 U.S.C. section 15962(i)) states:
``No technology, or level of emission reduction, solely by
reason of the use of the technology, or the achievement of the
emission reduction, by 1 or more facilities receiving assistance
under this Act, shall be considered to be--(1) adequately
demonstrated for purposes of section 111 of the Clean Air Act (42
U.S.C. 7411)[.]''
In a February 26, 2014 Notice of Data Availability, the EPA
proposed to give this provision its natural meaning: the term
``solely'' modifies all of the provisions, so that any ``adequately
demonstrated'' finding by the EPA could not be based solely upon
technology, level of emission reduction, or achievement of the
emission reduction by a facility (or facilities) receiving
assistance. The EPA proposes the same interpretation here. The EPA
further believes that its proposed determination of the ``best
system of emission reduction . . . adequately demonstrated'' does
not depend exclusively on technology, level of emission reduction,
or achievement of emission reduction from facilities receiving EPAct
assistance, given the myriad number of technologies and emission
performance on which that proposed determination is based.
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1. Overview of Approach
In considering the appropriate scope of the proposed BSER, the EPA
evaluated three basic groupings of strategies for reducing
CO2 emission from EGUs: (i) Reductions achievable through
improvements in individual EGUs' emission rates (referred to throughout
this preamble as ``building block 1''); (ii) EGU CO2
emissions reductions achievable through re-dispatch from affected steam
EGUs to affected NGCC units (``building block 2''); and (iii) EGU
CO2 emissions reductions achievable by meeting demand for
electricity or electricity services through expanded use of low- or
zero-carbon generating capacity (``building block 3'') and through
expanded use of demand-side energy efficiency (``building block 4'').
While the first grouping plays the same role in each of our two
formulations of the BSER, the second and third groupings play different
roles: In the first formulation they constitute components of the BSER,
and in the second formulation they serve as the basis for why a
component of that formulation of the BSER--reduced utilization of the
higher-emitting affected EGUs--is adequately demonstrated.
As described in the remainder of this section, the EPA concluded
that while certain strategies within the first grouping clearly should
be part of the BSER, it was not appropriate to limit consideration of
the BSER to this first grouping, for several reasons. First, we
determined that some strategies available in the other two groupings
can support reduced CO2 emissions from the fossil fuel-fired
EGUs by significant amounts and at lower costs than some of the
strategies in the first grouping. Second, we observed that strategies
in all three groupings were already being pursued by states and sources
taking advantage of the integrated nature of the electricity system, at
least in part for the purpose of reducing CO2 emissions.
Third, we were concerned that if measures from the first grouping that
improve heat rates at coal-fired steam EGUs were implemented in
isolation, without additional measures that encourage substitution of
less carbon-intensive ways of providing electricity services for more
carbon-intensive generation, the resulting increased efficiency of
coal-fired steam units would provide incentives to operate those EGUs
more, leading to smaller overall reductions in CO2
emissions.\93\ These factors reinforced the appropriateness of our
considering strategies from all three groupings for purposes of
determining the BSER.
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\93\ Elsewhere in the preamble we refer to the potential for
efficiency improvements to lead to increased competitiveness and
therefore increased utilization as a ``rebound effect.''
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2. CO2 Reductions Achievable Through Improvements in
Individual EGUs' Emission Rates
The first grouping of CO2 emission reduction options
that the EPA evaluated as potential options for the BSER consists of
measures that can reduce individual EGUs' CO2 emission rates
(i.e., the amount of CO2 emitted per unit of electricity
\94\ output). These measures included improving the efficiency with
which EGUs convert fuel heat input to electricity output (i.e., heat
rate improvements), applying carbon capture and storage (CCS)
technology, and substituting lower-carbon fuels such as natural gas for
higher-carbon fuels such as coal (i.e., natural gas co-firing or
conversion).
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\94\ For simplicity, throughout this preamble we generally refer
to the energy output produced by EGUs as electricity, recognizing
that some EGUs produce a portion of their energy output in other
forms, such as steam for heating or process uses. The discussion
here applies to both EGUs that produce only electricity and EGUs
that produce a combination of electricity and other energy output.
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Our assessment of heat rate improvements showed that these measures
would achieve CO2 emission reductions at low costs, although
compared to other measures, the available reductions were relatively
limited in quantity.\95\ Specifically, our analysis indicated that
average CO2 emission reductions of 1.3 to 6.7 percent could
be achieved by coal-fired steam EGUs through adoption of best
practices, and that additional average reductions of up to four percent
could be achieved through equipment upgrades.\96\ Heat rate
improvements pay for themselves at least in part through reductions in
fuel costs, generally making this a relatively inexpensive approach for
reducing CO2 emissions. We estimated that CO2
reductions of between four and six percent from overall heat rate
improvements could be achieved on average across the nation's fleet of
coal-fired steam EGUs for net costs in a range of $6 to $12 per metric
ton.\97\
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\95\ The EPA assessed opportunities to achieve CO2
reductions through heat rate improvements at both coal-fired steam
EGUs and non-coal-fired fossil fuel-fired EGUs, such as oil/gas-
fired steam EGUs and NGCC units. At this time we are proposing that
the basis for supporting the BSER should include heat rate
improvements only at coal-fired steam EGUs, but we are inviting
comment on including heat rate improvements at other EGU types. See
Section VI.C.5 for further discussion of our assessment of heat rate
opportunities for non-coal-fired EGUs.
\96\ These estimated ranges are averages applicable to the fleet
of coal-fired steam EGUs as a whole. Potential improvements at
individual EGUs could be higher or lower.
\97\ As noted above, in the absence of other kinds of
CO2 emission reduction measures, the emission reductions
achievable through heat rate improvements could be offset to some
extent by increased utilization of EGUs making the improvements (a
``rebound effect''). See Section VI.C.1 below for further
discussion.
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The EPA also examined application of CCS technology at existing
EGUs. CCS offers the technical potential for CO2 emission
reductions of over 90 percent, or smaller percentages in partial
applications. In the recently proposed Carbon Pollution Standards for
new fossil fuel-fired EGUs (79 FR 1430), we found that partial CCS was
adequately demonstrated for new fossil fuel-fired steam EGUs and
integrated gasification
[[Page 34857]]
combined cycle (IGCC) units. We also found that for these new units the
costs were not unreasonable, either for individual units or on a
national basis, and we proposed to find that application of partial CCS
is the BSER. However, application of CCS at existing units would entail
additional considerations beyond those at issue for new units.
Specifically, the cost of integrating a retrofit CCS system into an
existing facility would be expected to be substantial, and some
existing EGUs might have space limitations and thus might not be able
to accommodate the expansion needed to install CCS. Further, the
aggregated costs of applying CCS as a component of the BSER for the
large number of existing fossil fuel-fired steam EGUs would be
substantial and would be expected to affect the cost and potentially
the supply of electricity on a national basis. For these reasons,
although some individual facilities may find implementation of CCS to
be a viable CO2 mitigation option in their particular
circumstances,\98\ the EPA is not proposing and does not expect to
finalize CCS as a component of the BSER for existing EGUs in this
rulemaking.\99\ Nevertheless, CCS would be available to states and
sources as a compliance option.
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\98\ CCS already has been or is being implemented at some
existing EGUs, as noted in the discussion of CCS later in the
preamble.
\99\ As noted later in this preamble, we are nevertheless
seeking comment on the extent to which existing EGUs could implement
CCS in order to improve our understanding.
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Natural gas co-firing or conversion at coal-fired steam EGUs offers
greater potential CO2 emission reductions than heat rate
improvements, but at a higher cost (although less than the cost of
applying CCS technology). Because natural gas contains less carbon than
an energy-equivalent quantity of coal, converting a coal-fired steam
EGU to burn only natural gas would reduce the unit's CO2
emissions by approximately 40 percent. The CO2 reductions
are generally proportional to the amount of gas substituted for coal,
so if an EGU continued to burn mostly coal while co-firing natural gas
as, for example, 10 percent of the EGU's total heat input, the
CO2 emission reductions would be approximately four percent.
The EPA determined that the most significant cost associated with
natural gas conversion or co-firing is likely to be the incremental
cost of natural gas relative to the cost of coal. Using Energy
Information Administration (EIA) fuel price projections, we estimated
that the CO2 reductions achieved through natural gas
conversion or co-firing at an average coal-fired steam EGU would have
costs ranging from approximately $83 to $150 per metric ton.\100\ Thus,
although there have been past instances where coal-fired steam EGUs
have been converted to natural gas, and we expect some additional
future conversions where circumstances at individual EGUs make the
option particularly attractive, for the industry as a whole we would
expect that other approaches could reduce CO2 emissions from
existing EGUs at lower cost. However, gas conversion or co-firing would
be available to states and sources as a compliance option, and, as
noted later in the preamble, we are seeking comment on whether this
option should be considered part of the BSER.
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\100\ The lower end of the range is for conversion to 100
percent natural gas, which would allow EGUs to eliminate certain
fixed operating and maintenance costs associated with coal use but
not natural gas use. See Section VI.C.5.a below for further
discussion.
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3. CO2 Emission Reductions Achievable Through Re-Dispatch
From Steam EGUs to NGCC Units
The second grouping of CO2 emission reduction options
evaluated by the EPA in the BSER analysis involves reducing emissions
by shifting generation among affected EGUs. An obvious alternative to
substituting natural gas for coal at individual steam EGUs through
conversion or co-firing is instead to use natural gas to generate
electricity at a different affected EGU with a better heat rate--
notably a natural gas combined cycle (NGCC) unit--and to substitute
that electricity for electricity from the coal-fired steam EGU, thus
resulting in lower emissions from the coal-fired steam EGU and lower
emissions from the set of affected EGUs overall.\101\ The electricity
system is physically interconnected or networked and operated on an
integrated basis across large regions. System operators routinely
increase or decrease the electricity output of individual EGUs to
respond to changes in electricity demand, equipment availability, and
relative operating costs (or bid prices) of individual EGUs while
observing reliability-related constraints. It has long been common
industry practice for system operators to choose from among multiple
EGUs when deciding which EGU to ``dispatch'' to generate the next
increment of electricity needed to meet demand. Thus, the well-
established practices of the industry support our evaluation of ``re-
dispatch'' of generation from steam EGUs to NGCC units as a potential
component of the basis for the BSER to reduce CO2 emissions
from existing EGUs.
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\101\ Strategies in this grouping also include shifting
generation from steam EGUs burning oil or natural gas to more
efficient NGCC units.
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NGCC units can produce as much as 46 percent more electricity from
a given quantity of natural gas than steam EGUs,\102\ making the re-
dispatch approach a significantly less expensive way to reduce
CO2 emissions than conversion or co-firing of coal-fired
steam EGUs to burn natural gas. For example, using the same EIA fuel
cost projections as were used above to estimate the costs of natural
gas conversion or co-firing, we estimated that the cost of
CO2 reductions achievable by substituting electricity from
an existing NGCC unit for electricity from an average coal-fired steam
EGU would be approximately $30 per metric ton.\103\
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\102\ This estimate assumes an average heat rate of 10,434 Btu/
kWh for coal fossil fuel-fired steam units between 400 and 600 MW
and 7,130 Btu/kWh for NGCC units between 400 and 600 MW. See
NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
\103\ See Section VI.C.2 below for further discussion.
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Our analysis indicated that the potential CO2 reductions
available through re-dispatch from steam EGUs to NGCC units are
substantial. As of 2012, there was approximately 245 GW of NGCC
capacity in the United States, 196 GW of which was placed in service
between 2000 and 2012.\104\ In 2012, the average utilization rate of
U.S. NGCC capacity was 46 percent, well below the utilization rates the
units are capable of achieving. In 2012 approximately 10 percent of
NGCC plants operated at annual utilization rates of 70 percent or
higher, and 19 percent of NGCC units operated at utilization rates of
at least 70 percent over the summer season. Average reported
availability generally exceeds 85 percent. We recognize that the
ability to increase NGCC utilization rates may also be affected by
infrastructure and system considerations, such as limits on the ability
of the natural gas industry to produce and deliver the increased
quantities of natural gas, the ability of steam EGUs to reduce
generation while remaining ready to supply electricity when needed in
peak demand hours, and the ability of the electric transmission system
to accommodate the changed geographic pattern of generation. However,
these considerations have not limited past rapid increases in NGCC
generation levels, as indicated by a 20 percent increase in natural gas
consumption for
[[Page 34858]]
electricity generation from 2011 to 2012.\105\ Further, we have taken
these considerations into account, and the proposal's compliance
schedule provides flexibility and time for investment in additional
natural gas and electric industry infrastructure if needed.
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\104\ EIA Form 860, available at http://www.eia.gov/electricity/data/eia860. In comparison, in 2012 there was 336 GW of coal steam
capacity, of which 22 GW was placed in service between 2000 and
2012. Id.
\105\ EIA Form 923, available at http://www.eia.gov/electricity/data/eia923/.
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As discussed below in Section VI.C.2, the data and considerations
cited above support our assessment that an average NGCC utilization
rate in a range of 65 to 75 percent is a reasonable target for the
amount of additional NGCC generation that could be substituted for
higher carbon generation from steam EGUs as part of the BSER.\106\ If
re-dispatch consistent with a target average NGCC utilization rate of
70 percent had been achieved in 2012, the combined CO2
emissions of steam EGUs and NGCCs would have been reduced by
approximately 13 percent.
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\106\ Substitution would only occur to the extent that there is
both NGCC capacity whose generation could be increased and steam
EGUs whose generation could be decreased.
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Finally, we also note that mechanisms for encouraging re-dispatch
as a CO2 reduction measure have already been developed and
applied in the industry. Under both RGGI and California's Global
Warming Solutions Act, shifting generation from more carbon-intensive
EGUs to less carbon-intensive EGUs is a way to facilitate compliance
with regulatory requirements. In both cases, the industry has
demonstrated the ability to respond to the regulatory requirements of
these state programs.
4. CO2 Emission Reductions Achievable Through Other Actions
Underway in the Industry
The third grouping of CO2 emission reduction options the
EPA evaluated in the BSER analysis encompasses other measures already
used in the industry and not included in the first two groupings. From
our evaluation of re-dispatch as an option for reducing CO2
emissions, it was apparent that relevant factors for consideration
include the integrated nature of the electricity system and the fact
that particular measures capable of reducing CO2 emissions
at EGUs were already being used and would continue to be used
throughout the industry, either for the purpose of compliance with
CO2 emission reduction requirements or to serve other
purposes and policy goals. That observation led us to consider what
other potential actions and options the industry was already using that
had resulted in or could result in, or support, the reduction of
CO2 emissions at EGUs. Again, we observed many such
instances, some taking place incidental to the routine operation of the
electricity system and others taking place in response to specific
state initiatives to reduce CO2 emissions from the power
sector. We concluded that there are two principal types of such
potential options for measures that support CO2 emission
reductions at EGUs affected under this proposal: Ongoing development
and use of low- and zero-carbon generating capacity, and ongoing
development and application of demand-side energy efficiency measures.
Low-and zero-carbon generating capacity provides electricity that
can be substituted for generation from more carbon-intensive EGUs. More
than half the states already have established some form of state-level
renewable energy requirements, with targets calling on average for
almost 20 percent of 2020 generation to be supplied from renewable
sources. The EPA is unaware of analogous state policies to support
development of new nuclear units, but 30 states already have nuclear
EGUs (with five units under construction) and the generation from these
units is currently helping to avoid CO2 emissions from
fossil fuel-fired EGUs. Policies that encourage development of
renewable energy capacity and discourage premature retirement of
nuclear capacity could be useful elements of CO2 reduction
strategies and are consistent with current industry behavior. Costs of
CO2 reductions achievable through these policies have been
estimated in a range from $10 to $40 per metric ton.\107\
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\107\ See Section VI.C.3 below for further discussion.
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Demand-side energy efficiency programs produce electricity-
dependent services with less electricity, and thereby support reduced
generation from existing fossil fuel-fired EGUs by reducing the demand
for that generation. Reduced generation results in lower CO2
emissions. More than 40 states already have established some form of
demand-side energy efficiency polices, and individual states have
avoided up to 13 percent of their electricity demand. Again, policies
that encourage demand-side energy efficiency could be useful elements
of CO2 reduction strategies and are consistent with current
industry behavior. Using conservatively high estimates of the costs of
demand-side energy efficiency, the EPA estimates that the costs of
CO2 emission reductions achievable consistent with such
policies would be in a range of $16 to $24 per metric ton.\108\
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\108\ See Section VI.C.4 below for further discussion.
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5. Summary of Building Blocks for the Best System of Emission Reduction
Based on the analytic approach summarized above, the EPA has
identified the following four principal categories--``building
blocks''--of measures that provide the foundation of our BSER
determination for CO2 emissions from existing EGUs:
1. Reducing the carbon intensity of generation at individual
affected EGUs through heat rate improvements.
2. Reducing emissions from the most carbon-intensive affected EGUs
in the amount that results from substituting generation at those EGUs
with generation from less carbon-intensive affected EGUs (including
NGCC units under construction).
3. Reducing emissions from affected EGUs in the amount that results
from substituting generation at those EGUs with expanded low- or zero-
carbon generation.
4. Reducing emissions from affected EGUs in the amount that results
from the use of demand-side energy efficiency that reduces the amount
of generation required.
Since they either result in improved operating efficiency or
support reductions in mass emissions at existing EGUs, each of the four
building blocks represents a demonstrated basis for reducing
CO2 emissions from affected EGUs that is already being
pursued in the power sector. In the next subsection, we discuss each of
the building blocks at length. Our approach for applying the building
blocks to each state's circumstances in order to develop state goals is
described in Section VII of this preamble.
C. Detailed Discussion of Building Blocks and Other Options Considered
In this subsection we discuss each of the building blocks in turn.
For each building block, we provide our proposed assessment of the
technical potential of the building block and the reasonableness of its
costs within the context of the BSER determination, and we describe how
we developed the data inputs used in the computations of the proposed
state goals described in Section VII.C and the alternate goals offered
for comment in Section VII.E. We also discuss certain measures that we
are not proposing to consider as part of the best system of emission
reduction. Additional detail is provided
[[Page 34859]]
in the Greenhouse Gas Abatement Measures TSD.
It is worth noting that although the discussion below necessarily
addresses the building blocks individually, states are not required to
pursue plans involving any given building block or to do so at any
particular level of stringency. Rather, states have flexibility to
establish plans to meet their state emission limitations using their
own preferred combinations of efficacious measures applied to the
extent determined appropriate by the states. The EPA expects that
states and affected EGUs are unlikely to limit themselves to the
measures in any single building block, but instead are likely to pursue
portfolios of measures from a combination of the actions encompassed in
the building blocks. In developing the data inputs to be used in
computing state goals, the EPA has estimated reasonable rather than
maximum possible implementation levels for each building block in order
to establish overall state goals that are achievable while allowing
states to take advantage of the flexibility to pursue some building
blocks more extensively, and others less extensively, than is reflected
in the goal computations, according to each state's needs and
preferences.
1. Building Block 1--Heat Rate Improvements
The first category of approaches to reducing CO2
emissions at affected fossil fuel-fired EGUs consists of measures that
reduce the carbon intensity of generation at individual coal-fired
steam EGUs \109\ by improving heat rate. Heat rate improvements are
changes that increase the efficiency with which an EGU converts fuel
energy to electric energy (and useful thermal energy in the case of
units that cogenerate steam for process use as well as electricity),
thereby reducing the amount of fuel needed to produce the same amount
of electricity and lowering the amount of CO2 produced as a
byproduct of fuel combustion. Heat rate improvements yield important
benefits to affected sources by reducing their fuel costs.
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\109\ A ``steam EGU'' is an EGU that combusts fuel in a boiler
and uses the combustion heat to create steam which is then used to
drive a steam turbine that drives a generator to create electricity.
In contrast, a ``combined cycle EGU'' combusts fuel in a combustion
turbine that directly drives a generator, and the waste heat is then
used to create steam which is used to drive a steam turbine that
drives a generator to create more electricity. Steam EGUs can
combust a wide variety of fuels including coal and natural gas.
Combined cycle EGUs are more efficient at converting fuel energy to
electric energy but are limited to gaseous or liquid fuels, most
commonly natural gas or distillate oil. Almost all existing coal-
fired EGUs are steam EGUs (the exceptions are integrated
gasification combined cycle (IGCC) units where coal is processed to
create a gaseous fuel that is then combusted in a combined cycle
unit).
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The EPA is aware of the potential for ``rebound effects'' from
improvements in heat rates at individual EGUs. In this context, a
rebound effect would occur where, because of an improvement in its heat
rate, an EGU experiences a reduction in variable operating costs that
makes the EGU more competitive relative to other EGUs and consequently
raises the EGU's generation output. The increase in the EGU's
CO2 emissions associated with the increase in generation
output would offset the reduction in the EGU's CO2 emissions
caused by the decrease in its heat rate and rate of CO2
emissions per unit of generation output. The extent of the offset would
depend on the extent to which the EGU's generation output increased (as
well as the CO2 emission rates of the EGUs whose generation
was displaced). The EPA considers the rebound effect to be a potential
concern if heat rate improvements were the only approaches being
considered for the BSER, but believes that the effect can be addressed
by establishing the BSER as a combination of approaches that includes
not only heat rate improvements but also approaches that will encourage
reductions in electricity demand or increases in generation from lower-
or zero-emitting EGUs. The topic of potential rebound effects is
discussed further in Sections VI.D and VI.E below. For purposes of the
remainder of this subsection, no rebound effect is assumed.
Although heat rate improvements have the potential to reduce
CO2 emissions from all types of affected EGUs, the EPA's
analysis indicates the potential is significantly greater for coal-
fired steam EGUs than for other EGUs, and for purposes of determining
the best system of emission reduction at this time, the EPA is
conservatively proposing to base its estimate of CO2
emission reductions from heat rate improvements on coal-fired steam
EGUs only.\110\ The remainder of this subsection focuses on the EPA's
analysis of potential heat rate improvements from coal-fired steam
EGUs. Our analysis of potential heat rate improvements from other types
of affected EGUs is addressed in Section VI.C.5 below.
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\110\ As noted in Section VI.C.5.d below, we are taking comment
on including heat rate improvement opportunities at other EGU types
in the basis for supporting the BSER. Also, for compliance purposes
states and EGUs would be able to rely on CO2 emission
reductions achieved through heat rate improvements at other types of
EGUs.
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a. Ability of Heat Rate Improvements To Reduce CO2 Emissions
The heat rate of an EGU is the amount of fuel energy input needed
(Btu, higher heating value basis) to produce 1 kWh of net electrical
energy output (and useful thermal energy in the case of cogeneration
units).\111\ The current weighted-average annual heat rate of U.S.
coal-fired EGUs in the range of 400 to 600 MW is approximately 10,434
Btu per net kWh.\112\ Because an EGU's CO2 emissions are
driven primarily by the amount of fuel consumed, at any fossil fuel-
fired EGU there is a strong correlation between potential heat rate
improvements and potential reductions in carbon-intensity.\113\
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\111\ Heat rate can also be expressed on a gross basis--i.e.,
fuel input per kWh of gross electricity generated--instead of a net
basis--i.e., fuel input per kWh of net electricity sent to the grid.
The difference between gross and net electricity is the amount of
electricity used at the plant to operate components such as pumps,
fans, motors, and pollution control devices.
\112\ See NEEDSv.5.13 at http://www.epa.gov/powersectormodeling/BaseCasev513.html.
\113\ A small portion of some fossil fuel-fired EGU's
CO2 emissions may come from sources other than fuel, such
as limestone or other carbonates used to capture sulfur dioxide
(SO2) and/or hydrogen chloride (HCl) in a scrubber or dry
injection system. However, CO2 emissions from these
reagents will also tend to be reduced by heat rate improvements,
because reagent usage, and the associated CO2 emissions,
will decrease when the amount of fuel used decreases.
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Several studies have examined the opportunities to employ heat rate
improvements as a means of reducing CO2 emissions from coal-
fired power plants.\114\ Among these, a 2009 study by the engineering
firm Sargent & Lundy used bottom-up engineering approaches evaluating
potential heat rate improvements from specific best practices and
equipment upgrades, including upgrades to boilers, steam turbines, and
control systems. Based on this study, the EPA believes that
implementation of all identified best practices and equipment upgrades
at a facility could provide total heat rate improvements in a range of
approximately 4 to 12 percent. (We recognize that individual EGUs would
only be able to implement the best practices or upgrades that were
applicable to their specific designs or fuel types and that had not
already been implemented.)
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\114\ See chapter 2 of the GHG Abatement Measures TSD for
details.
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In addition to the Sargent & Lundy study, which looked generically
at the types of improvements that can be made at specific types of
EGUs, historical heat rate data also provides a basis for
[[Page 34860]]
discerning the existence and possible magnitude of potential heat rate
improvements. Many EGUs regularly report to both the EPA and the U.S.
Department of Energy's Energy Information Administration (EIA)
CO2 emissions and generation data, from which heat input and
heat rate data can be computed. We have reviewed these data and have
identified several ``data apparent'' instances where an EGU's heat rate
experienced a substantial improvement in a short time--presumably
because of equipment upgrades installed at that point in time--that was
then sustained. These heat rate improvements ranged from 3 to 8
percent. In combination with bottom-up engineering analysis and the
further, more detailed EPA analysis of hourly data summarized below,
the individual EGU heat rate histories provide a strong basis for
considering heat rate improvement as a meaningful potential approach to
reducing the carbon intensity of generation at individual affected
fossil fuel-fired EGUs.
b. Amounts of Heat Rate Improvements
In order to estimate the technical potential of heat rate
improvement opportunities at existing fossil fuel-fired EGUs suggested
by the discussion above, the EPA pursued two principal areas of
analysis. The first area concerned the heat rate improvements that
could be achieved by reducing heat rate variability at individual coal-
fired EGUs through adoption of best practices for operation and
maintenance. The second area concerned heat rate improvement
opportunities that could be achieved through further equipment
upgrades. Both analyses are summarized below along with our
conclusions, and are discussed in greater detail in the GHG Abatement
Measures TSD.
For the best practices analysis, the EPA worked with the hourly
data reported to the EPA by affected EGUs subject to the monitoring and
reporting requirements of 40 CFR Part 75. The reported data include
hourly heat input and, for most reporting EGUs, hourly gross
generation, making it possible to compute hourly gross heat rates. We
used the hourly data to assess variability in the hourly gross heat
rates of approximately 900 individual coal-fired steam EGUs over the
period from 2002 to 2012. Specifically, the EPA evaluated the
consistency with which individual EGUs maintained their hourly heat
rates over time. We expected that a certain degree of short-term heat
rate variability was caused by factors beyond operators' control,
notably variation in hourly ambient temperature and hourly load, and
preliminary analysis confirmed our expectation. We therefore controlled
for variation in those factors by grouping the observed hourly heat
rate data for each EGU into subsets corresponding to ranges of hourly
ambient temperatures and hourly load levels.\115\ We believe that the
amount of residual variability within each data subset is an indication
of the degree of technical potential to improve the consistency with
which optimal heat rate performance is achieved by adopting operating
and maintenance best practices. For example, optimal heat rate
performance could be achieved with greater consistency through
practices such as turning off unneeded pumps at reduced loads,
installation of digital control systems, more frequent tuning of
existing control systems, or earlier like-kind replacement of worn
existing components. (Upgrades to existing equipment are considered
below.) By applying best practices to their operating and maintenance
procedures, owners and operators of EGUs could reduce heat rate
variability relative to average heat rates and, because the deviations
generally result in performance worse than the optimal heat rates,
improve the EGUs' average heat rates. Assuming that between 10 percent
and 50 percent of the deviation from top decile performance in each
subset of hourly heat rate observations within defined ranges of
temperature and load could be eliminated through adoption of best
practices, the result is a corresponding estimated range of 1.3 percent
to 6.7 percent technical potential for improvement in the average heat
rate of the entire fleet of coal-fired EGUs.\116\ Based on this
analysis, we believe a reasonable estimate for purposes of developing
state-specific goals is that affected coal-fired steam EGUs on average
could achieve a four percent improvement in heat rate through adoption
of best practices to reduce hourly heat rate variability. This estimate
corresponds to the elimination, on average across the fleet of affected
EGUs, of 30 percent of the deviation from top-decile performance in the
hourly heat rate for each EGU not attributable to hourly temperature
and load variation. We also solicit comment on the use of estimates up
to six percent, reflecting elimination on average of 50 percent of the
deviation from top-decile performance.
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\115\ Temperature data are from the National Oceanic and
Atmospheric Administration's Integrated Surface Data, http://www.ncdc.noaa.gov/data-access/land-based-station-data/land-based-datasets/integrated-surface-database-isd. Electrical generation data
are from the EPA's Air Markets Program Data, http://ampd.epa.gov/ampd/.
\116\ We examined whether the potential for heat rate
improvement varied based on EGU characteristics such as capacity,
boiler type, and location, and found no meaningful differences.
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For the equipment upgrade analysis, we evaluated potential
opportunities to improve heat rates at affected EGUs through specific
upgrades identified in the 2009 Sargent & Lundy study. In that study,
Sargent & Lundy estimated ranges of potential heat rate improvement
achievable through a variety of equipment upgrades. We screened the
upgrades from the study to identify what we consider to be a reasonable
subset of equipment upgrades that would generally be beyond the scope
of investments we would expect to be made for purposes of achieving the
best-practices heat rate improvements discussed above. Based on the
average of the study's ranges of potential heat rate improvements from
the various upgrades in this subset, implementation of the full subset
of appropriate opportunities at a single EGU could be expected to
result in an aggregate heat rate improvement of approximately four
percent (incremental to the improvement achievable from adoption of
best practices). However, we recognize that this total may overstate
the average equipment upgrade opportunity across all EGUs because some
EGUs may have already implemented some of these upgrades. We therefore
propose to use as a data input for purposes of developing state goals
an estimate that, on average across the fleet of affected EGUs, only
half of the full equipment upgrade opportunity just described remains--
i.e., that for the fleet of affected EGUs as a whole, the technical
potential for heat rate improvements from equipment upgrades
incremental to the best-practices opportunity is on average two percent
rather than four percent. We solicit comment on increasing this figure
up to four percent.
Some of the measures available to EGUs for reducing their carbon
intensity affect net heat rates rather than gross heat rates. Various
EGU components such as pumps, fans, motors, and pollution control
devices use electricity, a factor that is not accounted for in gross
heat rates (that is, fuel used per unit of gross energy output) but is
accounted for in net heat rates (that is, fuel used per unit of net
energy output sent to the electric grid or used for thermal purposes).
The electricity used by these components, referred to as auxiliary or
parasitic load, may represent from 4 to 12 percent of gross generation
at a coal-fired steam EGU.\117\ The analysis of
[[Page 34861]]
technical potential to reduce heat rate variability discussed above was
based on gross heat rate data. Like gross heat rate, parasitic load can
be addressed both through adoption of best practices and through
equipment upgrades, and some measures undertaken at EGUs may affect
parasitic load as well as gross heat rate. Because the hourly
generation data reported to the EPA represent gross generation, we have
less data available to directly analyze potential net heat rate
improvements than gross heat rate improvements. We have therefore not
included any separate estimate of parasitic load reductions achievable
through best practices in our goal-setting data inputs. However, these
opportunities would be available as a mechanism for reducing carbon-
intensity at affected EGUs and thus provide more flexibility and
opportunities for sources to improve their heat rates at reasonable
costs.\118\
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\117\ Electric Power Research Institute 2011 Technical Report--
Program on Technology Innovation: Electricity Use in the Electric
Sector (Opportunities to Enhance Electric Energy Efficiency in the
Production and Delivery of Electricity).
\118\ As proposed, the state-specific goals are expressed in the
form of CO2 emissions per net MWh, and reporting
requirements for sources would be in the same form, allowing
parasitic load reductions to contribute to improved measured heat
rates. If goals and reporting requirements were changed to a gross
MWh basis in the final rule, accounting for parasitic load
reductions as a source of CO2 reductions would require
additional procedures.
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The total of the estimated potential heat rate improvements from
adoption of best practices to reduce heat rate variability and
implementation of equipment upgrades as discussed above is six percent.
This total is used as the data input for heat rate improvements in the
computation of proposed state goals discussed in Section VII.C below.
Because of the close relationship between an EGU's fuel consumption and
its CO2 emissions, a six percent heat rate improvement would
be associated with a reduction in CO2 emissions of
approximately six percent. We believe that this represents a reasonable
estimate of the technical potential for CO2 emission
reductions that would be achievable from affected coal-fired steam
EGUs, on average, through heat rate improvements as an element of the
best system of emission reduction.
For purposes of developing the alternate set of goals on which we
are taking comment, as described in Section VII.E below, we have used a
more conservative estimate of a four percent heat rate improvement from
affected coal-fired EGUs on average. This level of improvement would be
consistent with those EGUs on average implementing best practices to
reduce heat rate variability without making further equipment upgrades,
or would be consistent with those EGUs on average implementing both
best practices and equipment upgrades, but to a lesser degree than we
have projected as being achievable for purposes of our proposal. We
view the four percent estimate as a reasonable minimum estimate of the
technical potential for heat rate improvement on average across
affected coal-fired steam EGUs.
c. Costs of Heat Rate Improvements
By definition, any heat rate improvement made for the purpose of
reducing CO2 emissions will also reduce the amount of fuel
the EGU consumes to produce its electricity output. The cost
attributable to CO2 emission reductions therefore would be
the net cost to achieve the heat rate improvement after any savings
from reduced fuel expense. As summarized below, we estimate that, on
average, the savings in fuel cost associated with a six percent heat
rate improvement would be sufficient to cover much of the associated
costs, with the result that the net costs of heat rate improvements
associated with reducing CO2 emissions from affected EGUs
are relatively low.
The EPA's most detailed estimates of the average costs required to
achieve the full range of heat rate improvements come from the 2009
Sargent & Lundy study discussed above. Based on the study, the EPA
estimated that for a range of heat rate improvements from 415 to 1205
Btus per kWh, corresponding to percentage heat rate improvements of 4
to 12 percent for a typical coal-fired EGU, the required capital costs
would range from $40 to $150 per kW. To correspond to the average heat
rate improvement of six percent that we have estimated to be achievable
through the combination of best practices and equipment upgrades, we
have estimated an average cost of $100 per kW, slightly above the
midpoint of the Sargent & Lundy study's range. At an estimated annual
capital charge rate of 14.3 percent, the carrying cost of an estimated
$100 per kW investment would be $14.30 per kW-year. For a coal-fired
EGU with a heat rate of 10,450 Btu per kWh, a utilization rate of 78
percent, and a coal price of $2.62 per MMBtu, a six percent heat rate
improvement would produce fuel cost savings of approximately $11.20 per
kW-year,\119\ leaving approximately $3.10 per kW-year of carrying cost
not recovered through fuel cost savings. At an average CO2
emission rate of 0.976 metric tons per MWh, the same six percent heat
rate improvement would reduce CO2 emissions by 0.40 metric
tons per kW-year.\120\ Thus, the average cost of CO2
reductions from heat rate improvements would be approximately $7.75 per
metric ton of CO2 ($3.10/0.40). If the average heat rate
improvement achievable for the $100 per kW investment were only four
percent, consistent with the heat rate improvement estimate in the
alternate goals on which we seek comment, the average cost of
CO2 reductions would be $11.63 per metric ton.\121\ On the
other hand, if an average heat rate improvement of four percent could
be achieved for an average investment of $50 per kW, reflecting an
assumption that the first improvements pursued would be the least
expensive ones, the average cost of CO2 reductions would
fall to $5.81 per metric ton.\122\
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\119\ 10,450 Btu/kWh * 8760 hours/year * 78% utilization * $2.62
per MMBtu * 6% improvement * 0.000001 MMBtu/Btu = $11.2 per kW-year.
Data inputs for average coal-fired EGU heat rate, average coal-fired
EGU utilization, and average coal price are from the IPM 5.13 base
case for 2020.
\120\ 8760 hours/year * 78% utilization * 0.976 metric tons/Mwh
* 6% improvement * 0.001 MW/kW = 0.40 metric tons of CO2
per kW-year. The estimated average coal-fired EGU CO2
emission rate per MWh is from the IPM 5.13 base case for 2020.
\121\ $7.75 per metric ton of CO2 * 6%/4% = $11.63
per metric ton of CO2.
\122\ $11.63 per metric ton of CO2 * $50/$100 = $5.81
per metric ton of CO2.
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The EPA recognizes that the simplified cost analysis just described
will represent the costs for some EGUs better than others because of
differences in EGUs' individual circumstances. We further recognize
that reductions in the utilization rates of coal-fired EGUs anticipated
from other components proposed for inclusion in the best system of
emission reduction would tend to reduce the fuel savings associated
with heat rate improvements, thereby raising the effective cost of
achieving the CO2 emission reductions from the heat rate
improvements. Nevertheless, we still expect that the majority of the
investment required to capture the technical potential for
CO2 emission reductions from heat rate improvements would be
offset by fuel savings, and that the net costs of heat rate
improvements as an approach to reducing CO2 emissions from
existing fossil fuel-fired EGUs are reasonable.
Based on the analyses of technical potential and cost summarized
above, we propose to find that a six percent reduction in the
CO2 emission rate of the coal-fired EGUs in a state, on
average, is a reasonable estimate of the amount of heat rate
improvement that can be implemented at a reasonable cost.\123\
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\123\ We note that although we expect that heat rate
improvements are also available from other fossil fuel-fired EGUs,
we have conservatively not included CO2 emission rate
reductions for those EGUs in the state goals. However, as discussed
in Section VI.C.5.d below, we are requesting comment on this aspect
of the proposal. Further, states and sources would be free to use
heat rate improvements at those other units to help reach the state
goals.
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[[Page 34862]]
We invite comment on all aspects of our analyses and findings
related to heat rate improvements, both as summarized here and as
further discussed in the Greenhouse Gas Abatement Measures TSD. As
noted earlier, we specifically request comment on increasing the
estimates of the amounts of heat rate improvement achievable through
adoption of best practices for operation and maintenance and through
equipment upgrades up to six percent and four percent, respectively,
representing a total potential improvement of up to ten percent,
particularly in light of the reasonable cost of heat rate improvements.
We also solicit comment on the quantitative impacts on the net heat
rates of coal-fired steam EGUs of operation at loads less than the
rated maximum unit loads.
2. Building Block 2--Dispatch Changes Among Affected EGUs
The second element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs goes to the achievement of reductions in mass emissions
at certain affected EGUs--in particular, fossil fuel-fired steam EGUs--
and entails an analysis of the extent to which generation at the most
carbon-intensive affected EGUs--again, in particular, fossil fuel-fired
steam EGUs--can be replaced with generation at less carbon-intensive
affected fossil fuel-fired EGUs--in particular, NGCC units that were in
operation or had commenced construction as of January 8, 2014, and are
therefore affected units for purposes of this rule.
a. Ability of Re-Dispatch To Reduce CO2 Emissions
The nation's EGUs are interconnected by transmission grids
extending over large regions. EGU owners and grid operators, subject to
various reliability and operational constraints, use the flexibility
provided by these interconnections to prioritize among available EGUs
when deciding which units should be called upon (i.e., ``dispatched'')
to increase or decrease generation in order to meet electricity demand
at any point in time. Recognizing that increments of generation are to
some extent interchangeable, dispatch decisions are based on
electricity demand at a given point in time, the variable costs of
available generating resources, and system constraints. This system of
security-constrained economic dispatch assures reliable and affordable
electricity. Electricity demand varies across geography and time in
response to numerous conditions, such that EGU owners and grid
operators are constantly responding to changes in demand and ``re-
dispatching'' to meet demand in the most reliable and cost-effective
manner possible. Since the enactment and implementation of Title IV of
the CAA Amendments of 1990, in regions where EGUs are subject to
market-based programs to limit emissions of pollutants such as
SO2 and NOX, the costs of emission allowances
have been factored directly into those EGUs' variable costs, like the
variable costs of operating pollution control devices, and have thereby
been accounted for in least-cost economic dispatch decisions by grid
operators. Similarly, operators of EGUs subject to CO2
emissions limits in RGGI now include the cost of RGGI CO2
allowances in those EGUs' variable costs,\124\ creating economic
incentives to replace generation at higher-emitting EGUs with
generation from lower-emitting sources to reduce CO2
emissions at the former through the process of least-cost economic
dispatch. As an alternate mechanism, permitting authorities can impose
limits on utilization or CO2 emissions at higher-emitting
EGUs, in which case grid operators and other market participants would
use the integrated electricity system to find other ways to meet the
demand for electricity services, either through demand-side energy
efficiency or through increased generation from lower-emitting EGUs. In
either case, whether implemented through economic mechanisms or permit
limitations, reducing emissions at high carbon-intensity EGUs is
technically feasible and can reduce overall power sector CO2
emissions because generation at such EGUs can be replaced by generation
at less carbon-intensive EGUs.
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\124\ The PJM market monitor publishes breakdowns of wholesale
energy prices, including a CO2 emission allowance cost
component, based on analysis of the prices bid by the ``marginal''
EGUs. See Monitoring Analytics, 2013 State of the Market Report for
PJM at 103-05, tbls. 3-63 & 3-64 (2014), available at http://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2013.shtml.
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We have also analyzed potential upstream net methane emissions
impact from natural gas and coal for the impacts analysis. This
analysis indicated that any net impacts from methane emissions are
likely to be small compared to the CO2 emissions reduction
impacts of shifting power generation from coal-fired steam EGUs to NGCC
units. Further information on our analysis of upstream impacts can be
found in Appendix 3A of the RIA.
b. Magnitude of Re-Dispatch
Having identified replacing generation at higher-emitting EGUs with
generation at lower-emitting EGUs as a technically feasible
CO2 emissions reduction strategy, we next address the
quantity of replacement generation that may be relied upon at
reasonable costs. The U.S. electric generating fleet includes EGUs
employing a variety of generating technologies. EGUs using technologies
with relatively low variable costs, such as nuclear units, are for
economic reasons generally operated at their maximum output whenever
they are available. Renewable EGUs such as wind and solar units also
have low variable costs, but in any event are generally operated when
wind and sun conditions permit rather than at operators' discretion. In
contrast, fossil fuel-fired EGUs have higher variable costs and are
also relatively flexible. Fossil fuel-fired EGUs are therefore
generally the units that operators use to respond to intra-day and
intra-week changes in demand. Because of these typical characteristics
of the various EGU types, the primary re-dispatch opportunities among
existing units available to EGU owners and grid operators generally
consist of opportunities to shift generation among various fossil fuel-
fired units, in particular between coal-fired EGUs (as well as oil- and
gas-fired steam EGUs) and NGCC units. In the shortterm--that is, over
time intervals shorter than the time required to build a new EGU--
fossil fuel-fired units consequently tend to compete more with one
another than with nuclear and renewable EGUs. The amount of re-dispatch
from coal-fired EGUs to NGCC units that takes place as a result of this
competition is highly relevant to overall power sector GHG emissions,
because a typical NGCC unit produces less than half as much
CO2 per MWh of electricity generated as a typical coal-fired
EGU.
In order to estimate the potential magnitude of the opportunity to
reduce power sector CO2 emissions through re-dispatch among
existing EGUs, the EPA first examined information on the design
capabilities and availability of NGCC units. This examination showed
that, although most NGCC units have historically been operated in
intermediate-duty roles for economic reasons, they are technically
capable of
[[Page 34863]]
operating in base-load roles at much higher annual utilization rates.
Average annual availability (that is, the percentage of annual hours
when an EGU is not in a forced or maintenance outage) for NGCC units in
the U.S. generally exceeds 85 percent, and can exceed 90 percent for
some groups.\125\
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\125\ See, e.g., North American Electric Reliability Corp.,
2008-2012 Generating Unit Statistical Brochure--All Units Reporting,
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher
Availability of Gas Turbine Combined Cycle, Power Engineering (Feb.
1, 2011), http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbine-combined-cycle.html.
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We also researched historical data to determine the utilization
rates that NGCC units have already been demonstrated capable of
sustaining. Over the last several years, EGU owners and grid operators
have engaged in considerable re-dispatch among various types of fossil
fuel-fired units relative to historical dispatch patterns, with NGCC
units increasing generation and many coal-fired EGUs reducing
generation. In fact, in April 2012, for the first time ever the total
quantity of electricity generated nationwide from natural gas was
approximately equal to the total quantity of electricity generated
nationwide from coal.\126\ These changes in generation patterns have
been driven largely by changes over time in the relative prices of
natural gas and coal, in addition to lower overall demand for
electricity. Although the relative fuel prices vary by location, as do
the recent patterns of re-dispatch, this trend holds across broad
regions of the U.S. In the aggregate, the historical data provide ample
evidence indicating that, on average, existing NGCC units can achieve
and sustain utilization rates higher than their present utilization
rates.
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\126\ Today in Energy, EIA (June 6, 2012) (http://www.eia.gov/todayinenergy/detail.cfm?id=6990).
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The experience of relatively heavily used NGCC units provides an
additional indication of the degree of increase in average NGCC unit
utilization that is technically feasible. According to the historical
NGCC unit utilization rate data reported to the EPA, in 2012 roughly 10
percent of existing NGCC units operated at annual utilization rates of
70 percent or higher.\127\ In effect, these units were being dispatched
to provide base-load power. In addition to the 10 percent of NGCC units
that operated at a 70 percent utilization rate on an annual basis, some
NGCC units operated at high utilization rates for shorter, but still
sustained, periods of time in response to high cyclical demand. For
example, on a seasonal basis, a significant number of NGCC units have
achieved utilization rates between 50 and 80 percent; over the 2012
winter season (December 2011-February 2012) and summer season (June-
August 2012), about 16 percent and 19 percent of NGCC units,
respectively, operated at utilization rates of 70 percent or more
across these entire seasons.\128\ During the spring and fall periods
when electricity demand levels are typically lower, these units were
sometimes idled or operated at much lower capacity factors.
Nonetheless, the data clearly demonstrate that a substantial number of
existing NGCC units have proven the ability to sustain 70 percent
utilization rates for extended periods of time. We view this as strong
evidence that increasing the utilization rates of existing NGCC units
to 70 percent, not in every individual instance but on average, as part
of a comprehensive approach to reducing CO2 emissions from
existing high carbon-intensity EGUs, would be technically feasible.
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\127\ The corresponding percentages of NGCC units that in 2012
operated at annual utilization rates of at least 65 percent and at
least 75 percent were 16 percent and 6 percent, respectively.
\128\ Air Markets Program Data (at http://ampd.epa.gov/ampd/).
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For purposes of establishing state goals, historical (2012)
electric generation data are used to apply each building block and
develop each state's goal (expressed as an adjusted CO2
emission rate in lbs per MWh).\129\ In 2012, total electric generation
from existing NGCC units was 959 TWh.\130\ After the application of
NGCC re-dispatch toward a 70 percent target utilization rate, the total
generation from these existing sources is projected to be 1,390 TWh per
year. Adding in the NGCC units that had commenced construction before
January 8, 2014 (and are therefore existing sources for purposes of
this proposal) but were not yet in operation in 2012 increases the
projected total generation from the full set of existing NGCC units to
1,443 TWh per year.
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\129\ See Section VII for further explanation of how goals were
computed.
\130\ For covered sources.
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Although producing over 1,400 TWh of generation in 2020 from
existing NGCC units is not actually required, because states may choose
other abatement measures to reach the state goals, the EPA nevertheless
believes that producing this quantity of generation from this set of
NGCC units is feasible. As a reference point, NGCC generation increased
by approximately 430 TWh (an 80 percent increase) between 2005 and
2012. The EPA calculates that NGCC generation in 2020 could increase by
approximately 50 percent from today's levels. This reflects a smaller
ramp-up rate in NGCC generation than has been observed from 2005 to
2012. We also expect an increase in NGCC generation of this amount
would not impair power system reliability. As we note in the TSD on
Resource Adequacy and Reliability, the level of potential re-dispatch
can be accommodated within the flexible compliance requirements of the
rule. Similar conclusions have been reached in recent studies of the
potential impact of emission reductions from existing power
plants.\131\
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\131\ See Greenhouse Gas Emission Reductions From Existing Power
Plants: Options to Ensure Electric System Reliability (Analysis
Group, Inc., May 2014). Also see the Resource Adequacy Technical
Support Document.
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The EPA also examined the technical capability of the natural gas
supply and delivery system to provide increased quantities of natural
gas and the capability of the electricity transmission system to
accommodate shifting generation patterns. For several reasons, we
conclude that these systems would be capable of supporting the degree
of increased NGCC utilization needed for states to achieve the proposed
goals. First, the natural gas pipeline system is already supporting
national average NGCC utilization rates of 60 percent or higher during
peak hours, which are the hours when constraints on pipelines or
electricity transmission networks are most likely to arise. NGCC unit
utilization rates during the range of peak daytime hours from 10 a.m.
to 9 p.m. are typically 15 to 20 percentage points above their average
utilization rates (which have recently been in the range of 40 to 50
percent).\132\ Fleet-wide combined-cycle average monthly utilization
rates have reached 65 percent,\133\ showing that the pipeline system
can currently support these rates for an extended period. If the
current pipeline and transmission systems allow these utilization rates
to be achieved in peak hours and for extended periods, it is reasonable
to expect that similar utilization rates should also be possible in
other hours when constraints are typically less severe, and be reliably
sustained for other months of the year. The second consideration
supporting our view that natural gas and electricity system
[[Page 34864]]
infrastructure would be capable of supporting increased NGCC unit
utilization rates is the flexibility of the emission guidelines. The
state goals do not require any particular NGCC unit utilization rate to
be achieved in any hour or year of the initial plan period. Thus, even
if isolated natural gas or electricity system constraints were to limit
NGCC unit utilization rates in certain locations in certain hours, this
would not prevent an increase in NGCC generation overall across a state
or broader region and across all hours. The third consideration
supporting a conclusion regarding the adequacy of the infrastructure is
that pipeline and transmission planners have repeatedly demonstrated
the ability to methodically relieve bottlenecks and expand
capacity.\134\ Natural gas pipeline capacity has regularly been added
in response to increased gas demand and supply, such as the addition of
large amounts of new NGCC capacity from 2001 to 2003, or the delivery
to market of unconventional gas supplies since 2008. These pipeline
capacity increases have added significant deliverability to the natural
gas pipeline network to meet the potential demands from increased use
of existing NGCC units. Over a longer time period, much more
significant pipeline expansion is possible. In previous studies, when
the pipeline system was expected to face very large demands for natural
gas use by electric utilities about ten years ago, increases of up to
30 percent in total deliverability out of the pipeline system were
judged to be possible by the pipeline industry.\135\ There have been
notable pipeline capacity expansions over the past five years, and
substantial additional pipeline expansions are currently under
construction.\136\ Similarly, the electric transmission system is
undergoing substantial expansion.\137\ Further, as discussed below in
Sections VII.D and VIII of this preamble (on state flexibilities and
state plans, respectively), we believe the flexible nature of the
proposed goals provides time for infrastructure improvements to occur
should they prove necessary in some locations.\138\ Combining these
factors of currently observed average monthly NGCC utilization rates of
up to 65 percent, the flexibility of the emission guidelines, and the
availability of time to address any existing infrastructure
limitations, it is reasonable to conclude that the natural gas pipeline
system can reliably deliver sufficient natural gas supplies, and the
electric transmission system can reliably accommodate changed
generation patterns, to allow NGCC utilization to increase up to an
average annual utilization rate of 70 percent.
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\132\ EIA, Average utilization of the nation's natural gas
combined-cycle power plant fleet is rising, Today in Energy, July
9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA,
Today in Energy, Jan. 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data).
\133\ EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
\134\ See, e.g., EIA, Natural Gas Pipeline Additions in 2011,
Today in Energy; INGAA Foundation, Pipeline and Storage
Infrastructure Requirements for a 30 Tcf Market (2004 update); INGAA
Foundation, North American Midstream Infrastructure Through 2035--A
Secure Energy Future Report (2011).
\135\ Pipeline and Storage Infrastructure Requirements for a 30
Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas
groups confident of 30-tcf market, Oil and Gas Journal, 1999.
\136\ For example, between 2010 and April 2014, 118 pipeline
projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) were
placed in service, and between April 2014 and 2016 an additional 47
pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of
pipe) are scheduled for completion. Energy Information
Administration, http://www.eia.gov/naturalgas/data.cfm.
\137\ According to the Edison Electric Institute, member
companies are planning over 170 projects through 2024, with costs
totaling approximately $60.6 billion (this is only a portion of the
total transmission investment anticipated). Approxi- mately 75
percent of the reported projects (over 13,000 line miles) are high
voltage (345 kV and higher). http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_Project_lowres_bookmarked.pdf.
\138\ See Section VII.D and Section VIII below for discussion of
timing flexibility.
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We recognize that re-dispatch does contemplate an associated
increase in natural gas production, consistent with the current trends
in the natural gas industry. The EPA expects the growth in NGCC
generation assumed in goal-setting to be feasible and consistent with
domestic natural supplies. Increases in the natural gas resource base
have led to fundamental changes in the outlook for natural gas. There
is general agreement that recoverable natural gas resources will be
substantially higher for the foreseeable future than previously
anticipated, exerting downward pressure on natural gas prices.
According to EIA, proven natural gas reserves have doubled between 2000
and 2012. Domestic production has increased by 32 percent over that
same timeframe (from 19.2 TCF in 2000 to 25.3 TCF in 2012). EIA's
Annual Energy Outlook for 2014 projects that production will further
increase to 29.1 TCF, as a result of increased supplies and favorable
market conditions. For comparison, NGCC generation growth of 450 TWh
(calculated in goal setting) would result in increased gas consumption
of roughly 3.5 TCF for the electricity sector, which is less than the
projected increase in natural gas production.
The EPA notes that the assessments described above regarding the
ability of the electricity and natural gas industries to achieve the
levels of performance indicated for building block 2 in the state goal
computations are supported by analysis that has been conducted using
the Integrated Planning Model (IPM). IPM is a multi-regional, dynamic,
deterministic linear programming model of the U.S. electric power
sector that the EPA has used for over two decades to evaluate the
economic and emission impacts of prospective environmental policies. To
fulfill its purpose of producing projections related to the electric
power sector and its related markets--including least-cost capacity
expansion and electricity dispatch projections--that reflect industry
conditions in as realistic a manner as possible, IPM incorporates
representations of constraints related to fuel supply, transmission,
and unit dispatch. The model includes a detailed representation of the
natural gas pipeline network and the capability to project economic
expansion of the network based on pipeline load factors. At the EGU
level, IPM includes detailed representations of key operational
limitations such as turn-down constraints, which are designed to
account for the cycling capabilities of EGUs to ensure that the model
properly reflects the distinct operating characteristics of peaking,
cycling, and base load units.
As described in more detail below, the EPA used IPM to assess the
costs of requiring increasing levels of re-dispatch from higher- to
lower-emitting EGUs, and to that end, the EPA developed a series of
modeling scenarios that explored shifting generation from existing
coal-fired EGUs to existing NGCC units on a 1:1 basis within defined
areas.\139\ By the nature of IPM's design, those scenarios necessarily
also require compliance with the constraints just described (as
implemented for any specific scenario). IPM was able to arrive at a
solution for scenarios reflecting average NGCC utilization rates of 65,
70, and 75 percent, while observing the market, technical, and
regulatory constraints embedded in the model. Such a result is
consistent with the EPA's determination that increasing the utilization
rates of existing NGCC units to 70 percent, not in every individual
instance but on average, as part of a comprehensive approach to
reducing CO2 emissions from existing high carbon-intensity
EGUs, would be technically feasible.
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\139\ See Chapter 3 of the Regulatory Impact Analysis for more
detail.
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c. Cost of Re-Dispatch
Having established the technical feasibility and quantification of
replacing incremental generation at
[[Page 34865]]
higher-emitting EGUs with generation at NGCC facilities as a
CO2 emissions reduction strategy, we next turn to the
question of cost. The cost of the power sector CO2 emission
reductions that can be achieved through re-dispatch among existing
fossil fuel-fired EGUs depends on the relative variable costs of
electricity production at EGUs with different degrees of carbon
intensity. These variable costs are driven by the EGUs' respective fuel
costs and by the efficiencies with which they can convert fuel to
electricity (i.e., their heat rates). Historically, natural gas has had
a higher cost per unit of energy content (e.g., MMBtu) than coal in
most locations, but for NGCC units this disadvantage in fuel cost per
MMBtu relative to coal-fired EGUs is typically offset in significant
part, and sometimes completely, by a heat rate advantage.
The EPA has conducted two sets of extensive analyses to help inform
the development of the state-specific emission goals described in this
proposal, including analyses of the opportunity to reduce
CO2 emissions through re-dispatch. The first set was a
dispatch-only set that provided a framework for understanding the
broader economic and emissions implications of shifting generation to
NGCC units from more carbon-intensive EGUs without consideration of
emission reduction measures reflected in the other building blocks. The
second set included additional refinements and more closely reflected
all the characteristics of the proposed goals that were used as the
basis for assessing the costs and benefits of the overall
proposal.\140\ Both sets of analyses were conducted using IPM.
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\140\ See Regulatory Impact Analysis for more detail.
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The first set--the dispatch-only analyses--explored the magnitude
and cost of potential opportunities to shift generation from existing
coal-fired EGUs to existing NGCC units within defined areas. The
purpose of analyzing these scenarios was to understand and demonstrate
to what extent existing NGCC units could increase their dispatch at
reasonable costs and without significant impacts on other economic
variables such as the prices of natural gas and electricity. To
evaluate how EGU owners and grid operators could respond to a state
plan's possible requirements, signals, or incentives to re-dispatch
from more carbon-intensive to less carbon-intensive EGUs, the EPA
analyzed a series of scenarios in which the fleet of NGCC units
nationwide was required, on average, to achieve a specified annual
utilization rate.\141\ Specifically, the scenarios required average
NGCC unit utilization rates of at least 65, 70, and 75 percent,
respectively. For each scenario, we identified the set of dispatch
decisions that would meet electricity demand at the lowest total cost,
subject to all other specified operating and reliability constraints
for the scenario, including the specified average NGCC unit utilization
rate. Further, we allowed re-dispatch to occur exclusively within a
region's existing fleet.\142\
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\141\ The utilization rate constraint applied on average to all
NGCC units nationwide and did not apply to individual NGCC units or
to the fleets of NGCC units within individual states.
\142\ To best reflect the integrated nature of the electric
power sector, the EPA defined six regions for this analysis, the
borders of which are informed by North American Electric Reliability
(NERC) regions and Regional Transmission Organizations (RTOs). See
Chapter 3 of the Regulatory Impact Analysis for more detail.
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The costs and economic impacts of the various scenarios were
evaluated by comparing the total costs and emissions from each scenario
to the costs and emissions from a business-as-usual scenario. For the
scenario reflecting a 70 percent NGCC utilization rate, comparison to
the business-as-usual case indicates that the average cost of the
CO2 reductions achieved over the 2020-2029 period was $30
per metric ton of CO2.\143\ We view these estimated costs as
reasonable and therefore as supporting the use of a 70 percent
utilization rate target for purposes of quantifying the emission
reductions achievable at a reasonable cost through the application of
the BSER.
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\143\ The analogous costs for the scenarios with 65 and 75
percent NGCC utilization rates were $21 and $40 per metric ton of
CO2, respectively. For further detail on cost
methodology, data inputs, and results, refer to Chapter 3 of the GHG
Abatement Measures TSD.
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However, we also note that the costs just described are higher than
we would expect to actually occur in real-world compliance with this
proposal's goals. One reason for this is that the 70 percent
utilization rate in the scenario exaggerates the stringency with which
building block 2 is actually reflected in each of the state goals:
While the goal computation procedure uses 70 percent as a target NGCC
utilization rate for all states, for only 29 states do the goals
actually reflect reaching that target NGCC utilization, with the result
that the average NGCC utilization rate reflected in the computed state
goals is only 64 percent.\144\ Also, at least some states may be able
to achieve additional emission reductions through other components of
the BSER, and those other components may be relatively inexpensive. The
dispatch-only analyses were focused on evaluating the potential impacts
of re-dispatch in particular, and as a result, they reflect an
assumption that even in a state where re-dispatch might be relatively
expensive compared to other available CO2 emission reduction
measures that are part of the BSER, the state plan would rely on re-
dispatch to the same extent as the plans of other states. In practice,
under these circumstances, states would have flexibility to choose
among alternative CO2 reduction strategies that were part of
the BSER, instead of relying on re-dispatch to the maximum extent.
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\144\ For further explanation of the state goal computation
methodology, see Section VII of the preamble and the Goal
Computation TSD.
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The EPA also analyzed dispatch-only scenarios where shifting of
generation among EGUs was limited by state boundaries. In these
scenarios with less re-dispatch flexibility, the cost of achieving the
quantity of CO2 reductions corresponding to a nationwide
average NGCC unit utilization of 70 percent was $33 per metric ton.
Combining the results of the modeling with the factors likely to be
present in the real world reinforces the support we expressed above for
the 70 percent utilization rate. We remain concerned, however, that
higher NGCC utilization rates could be harder to sustain and could
exert further upward pressure on prices.
We invite comment on whether the regional or state scenarios should
be given greater weight in establishing the appropriate degree of re-
dispatch to incorporate into the state goals for CO2
emission reductions, and in assessing costs.
We also conclude from our analyses that the extent of re-dispatch
estimated in this building block can be achieved without causing
significant economic impacts. For example, in both of the 70 percent
NGCC unit utilization rate scenarios--with re-dispatch limited to
regional and state boundaries, respectively--delivered natural gas
prices were projected to increase by an average of no more than ten
percent over the 2020-2029 period, which is well within the range of
historical natural gas price variability.\145\ Projected wholesale
electricity price increases over the same period were less than seven
percent in both cases, which similarly is well within the range of
historical electric price variability.\146\
[[Page 34866]]
We view these projected impacts as not unreasonable and as supporting
use of a 70 percent NGCC utilization rate target for purposes of
quantifying the emission reductions achievable through application of
the BSER.
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\145\ According to EIA data, year-to-year changes in natural gas
prices at Henry Hub averaged 29.9 percent over the period from 2000
to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.
\146\ For example, year-on-year changes in PJM wholesale
electricity prices averaged 19.5 percent over the period from 2000
to 2013. Ventyx Velocity Suite, ISO real-time data for all hours.
Price variability for other eastern ISO regions (NYISO, ISO-NE., and
Midcontinent ISO) was similar. Id.
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However, for the same reasons discussed above with respect to
estimated costs per ton of CO2, in actual implementation we
again expect that the economic impacts shown in these scenarios,
including natural gas price impacts, are likely overstated compared to
the impacts that would actually occur in real-world compliance with
this rule's proposed goals. Consistent with this expectation, the
comprehensive analyses used to assess the compliance costs and benefits
of this proposal, which reflect a more complete representation of the
additional flexibility available to states, show significantly smaller
economic impacts. These analyses are discussed in Section X below.
Based on the analyses summarized above, the EPA proposes that for
purposes of establishing state goals, a reasonable estimate regarding
the degree of mass emission reductions achievable at fossil fuel-fired
steam EGUs can be determined based on the degree to which electricity
generation could be shifted from more carbon-intensive EGUs to less
carbon-intensive EGUs within the state at reasonable cost through re-
dispatch. The increment of emission reductions incorporated in this
component of our proposed BSER determination is commensurate with an
annual utilization rate for the state's NGCC units of up to 70 percent,
on average across all the NGCC units in the state.
For purposes of the alternative set of goals on which we are
seeking comment, we have used the less stringent target of a 65 percent
average utilization rate for NGCC units. In 2012, approximately 16
percent of existing NGCC plants larger than 25 megawatts had
utilization rates equal to or higher than this level. Also, as noted
earlier, average NGCC utilization nationwide is already over 60 percent
in some peak hours. We therefore view 65 percent as a reasonable lower-
bound estimate of an achievable average NGCC utilization rate, and we
would expect the costs and economic impacts from re-dispatch associated
with a 65 percent NGCC utilization target to be lower than the costs
and impacts associated with the 70 percent utilization target. Our cost
analysis indicated that CO2 emission reductions consistent
with a 65 percent average NGCC utilization rate could be achieved at a
cost of $21 per metric ton.
As discussed above, in addition to analyzing the impacts of using
the proposed 70 percent target utilization rate for existing NGCC
units, the EPA has also performed preliminary analysis of the impacts
of using a target utilization rate for existing NGCC units of 75
percent. That analysis showed that CO2 emission reductions
consistent with a 75 percent target utilization rate could be achieved
at a cost of $40 per metric ton.\147\ We invite comment on whether we
should consider options for a target utilization rate for existing NGCC
units greater than the proposed 70 percent target utilization rate.
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\147\ For further analysis related to the use of a 75 percent
target utilization rate for NGCC units, see chapter 3 of the GHG
Abatement Measures TSD.
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We invite comment on these proposed findings and on all other
issues raised by the discussion above and the related portions of the
Greenhouse Gas Abatement Measures TSD.
3. Building Block 3--Using an Expanded Amount of Less Carbon-Intensive
Generating Capacity
The third element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs also goes to the achievement of reductions in mass
emissions, but in this case the reductions would occur at all affected
EGUs, and entails an analysis of the extent to which generation at the
affected EGUs can be replaced by using an expanded amount of lower-
carbon generating capacity to produce replacement generation. Below we
discuss two types of generating capacity that can play this role:
Renewable generating capacity and new and preserved nuclear capacity.
a. Renewable Generating Capacity
Renewable electricity (RE) generating technologies are a well-
established part of the U.S. power sector. In 2012, electricity
generated from renewable technologies, including conventional
hydropower, represented 12 percent of total U.S. electricity
generation, up from 9 percent in 2005. More than half the states have
established renewable portfolio standards (RPS) that require minimum
proportions of electricity sales to be supplied with generation from
renewable generating resources.\148\ Production of this renewable
generation replaces predominantly fossil fuel-fired generation and
thereby avoids the CO2 emissions from that replaced
generation. The EPA believes that renewable electricity generation is a
proven way to assure reductions of CO2 emissions at affected
EGUs at a reasonable cost.\149\
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\148\ Database of State Incentives for Renewables & Efficiency
(DSIRE), http://www.dsireusa.org/summarymaps/index.cfm?ee=0&RE=0.
\149\ For discussion of how states and sources might use RE in
state plans, see Section VIII below.
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1. Proposed Quantification of Renewable Energy Generation
To estimate the CO2 emission reductions from affected
EGUs achievable based on increases in renewable generation, the EPA has
developed a ``best practices'' scenario for renewable energy generation
based on the RPS requirements already established by a majority of
states. The EPA views the existing RPS requirements as a reasonable
foundation upon which to develop such a scenario for two principal
reasons. First, in establishing the requirements, states have already
had the opportunity to assess those requirements against a range of
policy objectives including both feasibility and costs. These prior
state assessments therefore support the feasibility and cost of the
best practices scenario as well. Second, renewable resource development
potential varies by region, and the RPS requirements developed by the
states necessarily reflect consideration of the states' own respective
regional contexts.\150\
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\150\ The EPA recognizes that individual RPS policies vary in
their specification of where qualifying RE generation must occur.
However, the EPA believes the regional structure of this estimation
exercise supports a broad interpretation of RPS requirements across
states within a region as a proxy for reasonable-cost RE generation
potential within the same region.
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The EPA has not assumed any specific type of renewable generating
technology for the best practices scenario. Also, the scenario is not
an EPA forecast of renewable capacity development and neither
establishes RPS requirements that any state must meet nor makes any
determinations regarding allowable RE compliance measures. Rather, it
represents a level of renewable resource development for individual
states--with recognition of regional differences--that we view as
reasonable and consistent with policies that a majority of states have
already adopted based on their own policy objectives and assessments of
feasibility and cost.
As noted above, renewable resource potential varies regionally.
This geographic pattern is reflected in the existing RPS requirements
of the various states. Recognizing this pattern, the EPA has grouped
the states into six regions for purposes of developing the best
[[Page 34867]]
practices scenario.\151\ By comparing each state to a set of neighbors
rather than to a single national standard, we are able to take regional
variation into account while still maintaining a level of rigor for the
scenario's targets. The regional structure is informed by North
American Electric Reliability Corporation (NERC) regions and Regional
Transmission Organizations (RTOs), with adjustments to align regional
borders with state borders and to group Florida and Texas with
neighboring states.\152\ This structure accounts for similar power
system characteristics as well as geographic similarities in RE
potential. The grouping of states into the six regions is shown in
Table 5 below.
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\151\ Given their unique locations, Alaska and Hawaii are not
grouped with other states into these regions. As a conservative
approach to estimating RE generation potential in Alaska and Hawaii,
the EPA has developed RE generation targets for each of those states
based on the lowest values for the six regions evaluated here.
\152\ The regions are the same as those used in regional
modeling of this rule; see the Regulatory Impact Analysis for more
information on the regional modeling.
Table 5--Regions for Development of Best Practices RPS Scenario
----------------------------------------------------------------------------------------------------------------
Region States
----------------------------------------------------------------------------------------------------------------
East Central........................................... Delaware, District of Columbia*, Maryland, New Jersey,
Ohio, Pennsylvania, Virginia, West Virginia.
North Central.......................................... Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri,
North Dakota, South Dakota, Wisconsin.
Northeast.............................................. Connecticut, Maine, Massachusetts, New Hampshire, New
York, Rhode Island, Vermont*.
South Central.......................................... Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, Texas.
Southeast.............................................. Alabama, Florida, Georgia, Kentucky, Mississippi, North
Carolina, South Carolina, Tennessee.
West................................................... Arizona, California, Colorado, Idaho, Montana, Nevada,
New Mexico, Oregon, Utah, Washington, Wyoming.
----------------------------------------------------------------------------------------------------------------
* Because Vermont and the District of Columbia lack affected sources, no goals are being proposed for these
jurisdictions.
The best practices scenario for each state consists of increasing
annual levels of RE generation estimated based on application of an
annual RE growth factor to the state's historical RE generation,
subject to a maximum RE generation target. The annual RE growth factors
and maximum RE generation targets were developed separately for each of
the six regions. Our procedure for determining these elements is
described in the Greenhouse Gas Abatement Measures TSD and summarized
below.
The EPA first quantified the amount of renewable generation in 2012
in each state. The EPA then summed these amounts for all states in each
region to determine a regional starting level of renewable generation
prior to implementation of the best practices scenario. Hydropower
generation is excluded from this existing 2012 generation for purposes
of quantifying BSER-related RE generation potential because building
the methodology from a baseline that includes large amounts of existing
hydropower generation could distort regional targets that are later
applied to states lacking that existing hydropower capacity. The
exclusion of pre-existing hydropower generation from the baseline of
this target-setting framework does not prevent states from considering
incremental hydropower generation from existing facilities (or later-
built facilities) as an option for compliance with state goals.
Next, the EPA estimated the aggregate target level of RE generation
in each of the six regions assuming that all states within each region
can achieve the RE performance represented by an average of RPS
requirements in states within that region that have adopted such
requirements. For this purpose, the EPA averaged the existing RPS
percentage requirements that will be applicable in 2020 and multiplied
that average percentage by the total 2012 generation for the region. We
also computed each state's maximum RE generation target in the best
practices scenario as its own 2012 generation multiplied by that
average percentage. (For some states that already have RPS requirements
in place, these amounts are less than their RPS targets for 2030.)
For each region we then computed the regional growth factor
necessary to increase regional RE generation from the regional starting
level to the regional target through investment in new RE capacity,
assuming that the new investment begins in 2017, the year following the
initial state plan submission deadline,\153\ and continues through
2029. This regional growth factor is the growth factor used for each
state in that region to develop the best practices scenario.
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\153\ See Section VIII below for further discussion of timing
requirements for state plan submittals.
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Finally, we developed the annual RE generation levels for each
state. To do this, we applied the appropriate regional growth factor to
that state's initial RE generation level, starting in 2017, but
stopping at the point when additional growth would cause total RE
generation for the state to exceed the state's maximum RE generation
target. For computation of the proposed state goals discussed in
Section VII.C below, we used the annual amounts for the years 2020
through 2029. For computation of the alternate state goals discussed in
Section VII.E below, on which we are seeking comment, we used the
annual amounts for the years 2020 through 2024.
Alaska and Hawaii are treated as separate regions. Their RE targets
are based on the lowest regional RE target among the continental U.S.
regions and their growth factors are based upon historical growth rates
in their own RE generation. We invite comment regarding the treatment
of Alaska and Hawaii as part of this method.
For details on the regional targets and growth factors applied,
please refer to Chapter 4 of the GHG Abatement Measures TSD.
The cumulative RE amounts for each state, represented as
percentages of total generation, are shown in Table 6.
[[Page 34868]]
Table 6--State RE Generation Levels for State Goal Development
[Percentage of annual generation]\154\
----------------------------------------------------------------------------------------------------------------
Proposed goals Alternate goals
2012 ---------------------------------------------------------------
State (percent) Interim level Final level Interim level Final level
* (percent) (percent) * (percent) (percent)
----------------------------------------------------------------------------------------------------------------
Alabama......................... 2 6 9 4 5
Alaska.......................... 1 2 2 1 1
Arizona......................... 2 3 4 3 3
Arkansas........................ 3 5 7 4 5
California...................... 15 20 21 20 21
Colorado........................ 12 19 21 17 19
Connecticut..................... 2 5 9 4 5
Delaware........................ 2 7 12 4 5
Florida......................... 2 6 10 4 6
Georgia......................... 3 8 10 6 7
Hawaii.......................... 9 10 10 10 10
Idaho........................... 16 21 21 21 21
Illinois........................ 4 7 9 6 7
Indiana......................... 3 5 7 4 5
Iowa............................ 25 15 15 15 15
Kansas.......................... 12 19 20 19 20
Kentucky........................ 0 1 2 1 1
Louisiana....................... 2 5 7 4 4
Maine........................... 28 25 25 25 25
Maryland........................ 2 10 16 6 8
Massachusetts................... 5 15 24 11 13
Michigan........................ 3 6 7 5 6
Minnesota....................... 18 15 15 15 15
Mississippi..................... 3 8 10 6 8
Missouri........................ 1 2 3 2 2
Montana......................... 5 8 10 6 7
Nebraska........................ 4 8 11 6 7
Nevada.......................... 8 14 18 12 14
New Hampshire................... 7 19 25 15 19
New Jersey...................... 2 8 16 5 7
New Mexico...................... 11 18 21 16 18
New York........................ 4 11 18 8 10
North Carolina.................. 2 7 10 5 6
North Dakota.................... 15 15 15 15 15
Ohio............................ 1 6 11 4 5
Oklahoma........................ 11 19 20 18 20
Oregon.......................... 12 19 21 17 19
Pennsylvania.................... 2 9 16 5 7
Rhode Island.................... 1 4 6 3 3
South Carolina.................. 2 7 10 5 6
South Dakota.................... 24 15 15 15 15
Tennessee....................... 1 3 6 2 3
Texas........................... 8 16 20 13 15
Utah............................ 3 5 7 4 5
Virginia........................ 3 12 16 9 12
Washington...................... 7 12 15 10 11
West Virginia................... 2 8 14 5 6
Wisconsin....................... 5 8 11 7 8
Wyoming......................... 9 15 19 13 14
----------------------------------------------------------------------------------------------------------------
The EPA notes that for some states, the RE generation targets
developed using the proposed approach are less than those states'
reported RE generation amounts for 2012. We invite comment on whether
the approach for quantifying the RE generation component of each
state's goal should be modified to include a floor based on reported
2012 RE generation in that state.
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\154\ Vermont and the District of Columbia are excluded from
this table because we are not proposing goals for those
jurisdictions.
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This approach to quantification of a state's RE generation target
does not explicitly account for the amount of fossil fuel-fired
generation in that state. Without such an accounting, the application
of this approach could yield, for a given state, an increase in RE
generation that exceeds the state's reported 2012 fossil fuel-fired
generation.\155\ The EPA invites comment on whether this approach
should be modified so that the difference between a state's RE
generation target and its 2012 level of corresponding RE generation
does not exceed the state's
[[Page 34869]]
reported 2012 fossil fuel-fired generation.\156\
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\155\ In this proposed RE approach, this situation only occurs
with the RE targets quantified for the state of Washington.
\156\ For example, for the state of Washington the proposed
approach yields a final RE generation target of 17.7 TWh,
representing an increase of 9.5 TWh over Washington's reported 2012
RE generation (excluding hydropower) of 8.2 TWh. By comparison,
Washington's 2012 reported fossil fuel-fired generation was 9.4 TWh.
(The 2012 reported RE and fossil fuel-fired generation amounts for
all states are included in the Goal Computation TSD.) If the
limitation described in the text were applied to Washington, the
state's incremental quantified RE generation would be limited to 9.4
TWh, with the result that the state's final RE generation target
would be 17.6 TWh instead of 17.7 TWh.
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We note that with the exception of hydropower, the RE generation
levels represent total amounts of RE generation, rather than
incremental amounts above a particular baseline level. As a result,
this RE generation can be supplied by any RE capacity regardless of its
date of installation. This approach is therefore focused on quantifying
the fulfillment of each state's potential for the deployment of RE as
part of BSER using a methodology that does not require discriminating
between RE capacity that was installed before or after any given date.
Under this approach, states in a given region where a higher proportion
of total generation has already been achieved from renewable resources
are assumed to have less opportunity for deployment of additional
renewable generation as part of the BSER framework informing state
goals, in comparison to states in that region where the proportion of
total generation achieved from renewable resources to date has been
lower. That being said, the assumptions of RE generation used to
develop the state goals do not impose any specific RE generation
requirements on any state; they are only used to inform the
quantification of state goals to which states may respond with whatever
emission reduction measures are preferred.
With regard to hydropower, we seek comment regarding whether to
include 2012 hydropower generation from each state in that state's
``best practices'' RE quantified under this approach, and whether and
how the EPA should consider year-to-year variability in hydropower
generation if such generation is included in the RE targets quantified
as part of BSER. Chapter 4 of the GHG Abatement Measures TSD presents
state RE targets both with and without the inclusion of each state's
2012 hydropower generation.
2. Cost of CO2 Emission Reductions From RE Generation
The EPA believes that RE generation at the levels represented in
the best practices scenario can be achieved at reasonable costs.
According to an EPA analysis based on EIA levelized costs, the cost to
reduce emissions through RE ranges from $10 to $40 per metric ton of
CO2.\157\ Analysis of RE development in response to state
RPS policies also finds historical and projected costs of RPS-driven RE
deployment to be modest. One comparative analysis that ``synthesize[d]
and analyze[d] the results and methodologies of 28 distinct state or
utility-level RPS cost impact analyses'' projected the median change in
retail electricity price to be $0.0004 per kilowatt-hour (a 0.7 percent
increase), the median monthly bill impact to be between $0.13 and
$0.82, and the median CO2 reduction cost to be $3 per metric
ton.\158\ This finding has been confirmed with more recent RPS cost
data, including a report that determined 2010-2012 retail electricity
price impacts due to state RPS policies to be less than two percent,
with only two states experiencing price impacts of greater than three
percent.\159\ Additionally, the National Renewable Energy Laboratory
has projected low incremental costs for a range of scenarios reflecting
significant increases in RE penetration, including scenarios that
increase RE penetration to a range of 30 to 40 percent of national
generation, levels higher than those projected in our best practices
scenario.\160\
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\157\ This analysis is based upon EIA's AEO 2014 Estimated
Levelized Costs of Electricity for New Generation Sources, available
at http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
\158\ Chen et al., ``Weighing the Costs and Benefits of State
Renewable Portfolio Standards: A Comparative Analysis of State-Level
Policy Impact Projections,'' Lawrence Berkeley National Laboratory,
March 2007, available at http://emp.lbl.gov/publications/weighing-costs-and-benefits-state-renewables-portfolio-standards-comparative-analysis-s.
\159\ Galen Barbose, ``Renewables Portfolio Standards in the
United States: A Status Update,'' Lawrence Berkeley National Lab,
November 2013. Also to be published in Heeter et al., ``Estimating
the Costs and Benefits of Complying with Renewable Portfolio
Standards: Reviewing Experience to Date'' [review draft title].
UNPUBLISHED. National Renewable Energy Laboratory and Lawrence
Berkeley National Laboratory.
\160\ NREL, ``Renewable Electricity Futures Study'', NREL/TP-
6A20-52409, 2012, http://www.nrel.gov/analysis/re_futures/.
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While RPS requirements will continue to grow over time, the EPA
does not expect this anticipated expansion to fall outside the
historical norms of deployment or to create unusual pressure for cost
increases. Full compliance with current RPS goals through 2035 would
require approximately 4 to 4.5 GW of new renewable capacity per year.
Average deployment of RPS-supported renewable capacity from 2007 to
2012 exceeded 6 GW per year.\161\ In addition, recent improvements in
RPS compliance rates indicate to the EPA the reasonableness of current
RPS growth trajectories. Weighted average compliance rates among all
states have improved in each of the past three reported years (2008-
2011) from 92.1 percent to 95.2 percent despite a 40 percent increase
in RPS obligations during this period.\162\
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\161\ Galen Barbose, ``Renewables Portfolio Standards in the
United States: A Status Update,'' Lawrence Berkeley National
Laboratory, November 2013.
\162\ http://emp.lbl.gov/rps, retrieved March 2014. The RPS
compliance measure cited is inclusive of credit multipliers and
banked RECs utilized for compliance, but excludes alternative
compliance payments, borrowed RECs, deferred obligations, and excess
compliance. This estimate does not represent official compliance
statistics, which vary in methodology by state.
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We invite comment on this approach to treatment of renewable
generating capacity as a basis for the best system of emission
reduction adequately demonstrated and for quantification of state
goals.
3. Alternative Approach to Quantification of RE Generation
Additionally, the EPA is soliciting comment on an alternative
approach to quantification of renewable generation to support the BSER.
Unlike the proposed RE scenario described above that relies on a
regional application of state RPS commitments, the alternative
methodology relies on a state-by-state assessment of RE technical and
market potential. The alternative approach is based on two sources of
information: A metric representing the degree to which the technical
potential of states to develop RE generation has already been realized,
and IPM modeling of RE deployment at the state level under a scenario
that reflects a reduced cost of building new renewable generating
capacity.
The metric measuring realization of RE technical potential in a
state compares each state's existing renewable generation by technology
type with the technical potential for that technology in that state as
assessed by the National Renewable Energy Laboratory (NREL).\163\ This
comparison yields, for each state and for each RE technology, a
proportion of renewable generation technical potential that has been
achieved and can be represented as an RE development rate. For example,
if
[[Page 34870]]
a given state has 500 MWh of solar generation in 2012 while NREL
assesses that state's solar generation technical potential at 5,000
MWh/year, then that state's solar RE development rate would be ten
percent. The EPA then considers the range of RE development rates
across states in order to define a benchmark RE development rate for
each technology.
---------------------------------------------------------------------------
\163\ Lopez et al., NREL, ``U.S. Renewable Energy Technical
Potentials: A GIS-Based Analysis,'' (July 2012).
---------------------------------------------------------------------------
While a benchmark RE development rate offers a useful metric to
quantify the proportion of RE generation that would bring all states up
to a designated proportion of RE generation that has been achieved in
practice by certain states to date, such a metric does not explicitly
take into account the cost that would be faced to reach the benchmark
RE development rate in each state. In order to take this cost into
account, for this alternative approach the EPA has paired the benchmark
RE development rates described above with IPM modeling of RE deployment
at the state level, based on a scenario reflecting a reduced cost of
building new renewable generating capacity. The cost reduction for new
RE generating capacity is intended to represent the avoided cost of
other actions that could be taken instead to reduce CO2
emissions from the power sector. In the Alternative RE Approach TSD,
available in the docket, we show the RE deployment levels modeled using
a cost reduction of up to $30 per MWh, a level that is consistent with
the cost range of $10 to $40 per metric ton of avoided CO2
emissions estimated for the proposed RE scenario described above.\164\
---------------------------------------------------------------------------
\164\ Additional detail regarding this modeling and approach is
provided in the Alternative RE Approach TSD.
---------------------------------------------------------------------------
Under this alternative RE approach, the EPA would quantify RE
generation for each technology in each state as the lesser of (1) that
technology's benchmark rate multiplied by the technology's in-state
technical potential, or (2) the IPM-modeled market potential for that
specific technology. For example, if the benchmark RE development rate
for solar generation is determined to be 12 percent, and the
hypothetical state described above has a solar generation technical
potential of 5,000 MWh/year, then the benchmark RE development level of
generation for that state would be 600 MWh/year. If the IPM-modeled
market potential for solar generation in that state is 750 MWh/year,
then this approach would quantify solar generation for that state as
the benchmark RE development level (600 MWh/year) because it is the
lesser amount of those two measures.
Having quantified an amount of RE generation from each RE
technology in each state, the EPA would then determine for each state a
total level of RE generation that equals the sum of the generation
quantified for each of the assessed RE technologies in that state. If
the EPA were to adopt this alternative approach for quantifying RE in
BSER, these total levels of RE generation for each state would be
incorporated in state goals in place of the RE generation levels
quantified using the proposed approach described above. Further
methodological detail and state-level RE targets for this alternative
approach are provided in the Alternative RE Approach TSD in the docket.
We invite comment on this alternative approach to quantification of
RE generation to support the BSER. We note that the three specific
requests for comment made above with respect to the proposed
quantification approach--addressing, first, the possibility of a floor
based on 2012 RE generation, second, the possibility of a limitation
based on 2012 fossil fuel-fired generation and, third, the treatment of
hydropower generation--apply to this alternative approach as well.\165\
---------------------------------------------------------------------------
\165\ The Alternative RE Approach TSD presents the
quantification of hydropower generation under the alternative
approach, as well as the resulting state RE targets both with and
without hydropower generation included.
---------------------------------------------------------------------------
Finally, the EPA notes that the alternative RE approach described
above is one of a number of possible methodologies for using technical
and economic renewable energy potential to quantify RE generation for
purposes of state goals. The EPA invites comment on other possible
techno-economic approaches. For example, a conceptual framework for
another techno-economic approach is provided in the Alternative RE
Approach TSD.
b. New and Preserved Nuclear Capacity
Nuclear generating capacity facilitates CO2 emission
reductions at fossil fuel-fired EGUs by providing carbon-free
generation that can replace generation at those EGUs. Because of their
relatively low variable operating costs, nuclear EGUs that are
available to operate typically are dispatched before fossil fuel-fired
EGUs. Increasing the amount of nuclear capacity relative to the amount
that would otherwise be available to operate is therefore a technically
viable approach to support reducing CO2 emissions from
affected fossil fuel-fired EGUs.
1. Proposed Quantification of Nuclear Generation
One way to increase the amount of available nuclear capacity is to
build new nuclear EGUs. However, in addition to having low variable
operating costs, nuclear generating capacity is also relatively
expensive to build compared to other types of generating capacity, and
little new nuclear capacity has been constructed in the U.S. in recent
years; instead, most recent generating capacity additions have
consisted of NGCC or renewable capacity. Nevertheless, five nuclear
EGUs at three plants are currently under construction: Watts Bar 2 in
Tennessee, Vogtle 3-4 in Georgia, and Summer 2-3 in South Carolina. The
EPA believes that since the decisions to construct these units were
made prior to this proposal, it is reasonable to view the incremental
cost associated with the CO2 emission reductions available
from completion of these units as zero for purposes of setting states'
CO2 reduction goals (although the EPA acknowledges that the
planning for those units likely included consideration of the
possibility of future regulation of CO2 emissions from
EGUs). Completion of these units therefore represents an opportunity to
reduce CO2 emissions from affected fossil fuel-fired EGUs at
a very reasonable cost. For this reason, we are proposing that the
emission reductions achievable at affected sources based on the
generation provided at the identified nuclear units currently under
construction should be factored into the state goals for the respective
states where these new units are located. However, the EPA also
realizes that reflecting completion of these units in the goals has a
significant impact on the calculated goals for the states in which
these units are located. If one or more of the units were not completed
as projected, that could have a significant impact on the state's
ability to meet the goal. We therefore take comment on whether it is
appropriate to reflect completion of these units in the state goals and
on alternative ways of considering these units when setting state
goals.
Another way to increase the amount of available nuclear capacity is
to preserve existing nuclear EGUs that might otherwise be retired. The
EPA is aware of six nuclear EGUs at five plants that have retired or
whose retirements have been announced since 2012: San Onofre Units 2-3
in California, Crystal River 3 in Florida, Kewaunee in Wisconsin,
Vermont Yankee in Vermont, and Oyster Creek in New Jersey. While each
retirement decision
[[Page 34871]]
is based on the unique circumstances of that individual unit, the EPA
recognizes that a host of factors--increasing fixed operation and
maintenance costs, relatively low wholesale electricity prices, and
additional capital investment associated with ensuring plant security
and emergency preparedness--have altered the outlook for the U.S.
nuclear fleet in recent years. Reflecting similar concern for these
challenges, EIA in its most recent Annual Energy Outlook has projected
an additional 5.7 GW of capacity reductions to the nuclear fleet. EIA
describes the projected capacity reductions--which are not tied to the
projected retirement of any specific unit--as necessary to recognize
the ``continued economic challenges'' faced by the higher-cost nuclear
units.\166\ Likewise, without making any judgment about the likelihood
that any individual EGU will retire, we view this 5.7 GW, which
comprises an approximately six percent share of nuclear capacity, as a
reasonable proxy for the amount of nuclear capacity at risk of
retirement.
---------------------------------------------------------------------------
\166\ Jeffrey Jones and Michael Leff, EIA, ``Implications of
accelerated power plant retirements,'' (April 2014).
---------------------------------------------------------------------------
2. Cost of CO2 Emission Reductions From Nuclear Generation
We have determined that, based on available information regarding
the cost and performance of the nuclear fleet, preserving the operation
of at-risk nuclear capacity would likely be capable of achieving
CO2 reductions from affected EGUs at a reasonable cost. For
example, retaining the estimated six percent of nuclear capacity that
is at risk for retirement could support avoiding 200 to 300 million
metric tons of CO2 over an initial compliance phase-in
period of ten years.\167\ According to a recent report, nuclear units
may be experiencing up to a $6/MWh shortfall in covering their
operating costs with electricity sales.\168\ Assuming that such a
revenue shortfall is representative of the incentive to retire at-risk
nuclear capacity, one can estimate the value of offsetting the revenue
loss at these at-risk nuclear units to be approximately $12 to $17 per
metric ton of CO2. The EPA views this cost as reasonable. We
therefore propose that the emission reductions supported by retaining
in operation six percent of each state's historical nuclear capacity
should be factored into the state goals for the respective states.\169\
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\167\ Assuming replacement power for at-risk nuclear capacity is
sourced from new NGCC capacity at 800 lbs/MWh or the power system at
1127 lbs CO2/MWh (average 2020 power sector emissions
intensity as projected in the EPA's IPM Base Case).
\168\ ``Nuclear * * * The Middle Age Dilemma?'' Eggers, et al.,
Credit Suisse, February 2013.
\169\ A state's historical nuclear fleet is defined as all units
in commercial operation as of May 2014 with no current plans to
retire.
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For purposes of goal computation, generation from under-
construction and preserved nuclear capacity is based on an estimated 90
percent average utilization rate for U.S. nuclear units, consistent
with long-term average annual utilization rates observed across the
nuclear fleet. The methodology for taking this generation into account
for purposes of setting state emission rate goals is described below in
Section VII on state goals and in the Goal Computation TSD.
We invite comment on all aspects of the approach discussed above.
In addition, we specifically request comment on whether we should
include in the state goals an estimated amount of additional nuclear
capacity whose construction is sufficiently likely to merit evaluation
for potential inclusion in the goal-setting computation. If so, how
should we do so--for example, according to EGU owners' announcements,
the issuance of permits, projections of new construction by the EPA or
another government agency, or commercial projections? What specific
data sources should we consider for those permits or projections?
4. Building Block 4--Demand-Side Energy Efficiency
The fourth element of the foundation for the EPA's BSER
determination for reducing CO2 emissions at affected fossil
fuel-fired EGUs also supports reduced mass emissions at all affected
EGUs, and entails an analysis of the extent to which generation
reductions at the affected EGUs can be supported by reducing the demand
for generation at those EGUs through measures that reduce the overall
quantity of generation demanded by end-users.\170\
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\170\ Electricity end-users and electricity end-use referred to
throughout this subsection include the residential, commercial and
industrial sectors.
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a. Benefits of Demand-Side Energy Efficiency
Reducing demand for generation at affected EGUs through policies to
improve demand-side energy efficiency is a proven basis for reducing
CO2 emissions at those EGUs. Every state has established
demand-side energy efficiency policies, and many stakeholders
emphasized the success of these policies in reducing electricity
consumption by large amounts. For example, data reported to the U.S.
Energy Information Administration (EIA) show that in 2012 California
and Minnesota avoided 12.5 percent and 13.1 percent of their
electricity demand, respectively, through their demand-side efficiency
programs.\171\ Additionally, multiple studies have found that
significant improvements in end-use energy efficiency can be realized
at less cost than the savings from avoided power system costs.\172\
Increased investment in demand-side energy efficiency is being
supported by efforts at the federal, state, and local levels of
government as well as corporate efforts. Many stakeholders urged the
inclusion of demand-side energy efficiency policies as compliance
options under the CAA section 111(d) guidelines.
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\171\ Energy Information Administration Form 861, 2012,
available at http://www.eia.gov/electricity/data/eia861/.
\172\ See, e.g., Electric Power Research Institute, U.S. Energy
Efficiency Potential Through 2035 (Final Report, April 2014); Wang,
Yu and Marilyn A. Brown, Policy Drivers for Improving Electricity
End-Use Efficiency in the U.S.: An Economic-Engineering Analysis
(Energy Efficiency, 2014).
---------------------------------------------------------------------------
By reducing electricity consumption, energy efficiency avoids
greenhouse gas emissions associated with electricity generation.
Because fossil fuel-fired EGUs typically have higher variable costs
than other EGUs (such as nuclear and renewable EGUs), their generation
is typically the first to be replaced when demand is reduced.
Consequently, reductions in the utilization of fossil fuel-fired EGUs
can be supported by reducing electricity consumption and, by the same
token, reductions in electricity consumption avoid the CO2
emissions associated with the avoided generation. In this manner, in
2011, state demand-side energy efficiency programs are estimated to
have reduced CO2 emissions by 75 million metric tons.\173\
And when integrated into a comprehensive approach for addressing
CO2 emissions, demand-side energy efficiency improvements
offer even more potential to improve the carbon profile of the
electricity supply system. For example, if incentives exist to shift
generation to lower carbon-intensity EGUs, and those EGUs are fully
utilized, reducing demand can support further reductions in carbon
intensity. This potential effect reinforces the appropriateness of
incorporating demand-side efficiency improvements into a comprehensive
approach to address power sector CO2 emissions. In addition,
by supporting reductions in fossil fuel usage at EGUs, demand-side
[[Page 34872]]
energy efficiency supports not only reduced CO2 emissions
and carbon intensity of the power sector, but also reduced criteria
pollutant emissions, cooling water intake and discharge, and solid
waste production associated with fossil fuel combustion. By reducing
electricity usage significantly, energy efficiency also commonly
reduces the bills of electricity customers.
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\173\ Innovation, Electricity, Efficiency (an Institute of the
Edison Foundation), Summary of Customer-Funded Electric Efficiency
Savings, Expenditures, and Budgets (2011-2012) (March 2013),
available at http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.aspx.
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b. ``Best Practices'' for Demand-Side Energy Efficiency
To estimate the potential CO2 reductions at affected
EGUs that could be supported by implementation of demand-side energy
efficiency policies as a part of state goals, the EPA developed a
``best practices'' demand-side energy efficiency scenario. This
scenario provides an estimate of the potential for sources and states
to implement policies that increase investment in demand-side energy
efficiency technologies and practices at reasonable costs. It does not
represent an EPA forecast of business-as-usual impacts of state energy
efficiency policies or an EPA estimate of the full potential of end-use
energy efficiency available to the power system, but rather represents
a feasible policy scenario showing the reductions in fossil fuel-fired
electricity generation resulting from accelerated use of energy
efficiency policies in all states consistent with a level of
performance that has already been achieved or required by policies
(e.g., energy efficiency resource standards) of the leading states. The
data and methodology used to develop the best practices scenario are
summarized below.
We have not assumed any particular type of demand-side energy
efficiency policy. States with leading energy efficiency performance
have employed a variety of strategies that are implemented by a range
of entities including investor-owned, municipal and cooperative
electric utilities as well as state agencies and third-party
administrators. These include energy efficiency programs,\174\ building
energy codes, state appliance standards (for appliances without federal
standards), tax credits, and benchmarking requirements for building
energy use.\175\ Energy efficiency policies are designed to accelerate
the deployment of demand-side energy efficiency technologies,
practices, and measures by addressing market barriers and market
failures that limit their adoption. Some states have adopted energy
efficiency resource standards \176\ (EERS) to drive investment in
energy efficiency programs; some have relied on other strategies; most
states are using multiple policy approaches. Based on historical data
on energy efficiency program savings and analysis of the requirements
of existing state energy efficiency policies, twelve leading states
have either achieved--or have established requirements that will lead
them to achieve--annual incremental savings rates of at least 1.5
percent of the electricity demand that would otherwise have
occurred.\177\ The 1.5 percent savings rate is inclusive of, not
additional to, existing state energy efficiency requirements. These
savings levels are realized exclusively through the adoption and
implementation of energy efficiency programs. The energy savings data
underpinning these analyses are derived from energy efficiency program
reports required by state public utility commissions and other entities
with a similar oversight role.\178\ These state commissions define and
oversee the analysis and reporting requirements for energy efficiency
programs as part of their role of overseeing rates for utility
customers in their states. One typical requirement is the application
of recognized evaluation, measurement, and validation (EM&V) protocols
that specify industry-preferred approaches and methodologies for
estimating savings from efficiency programs.\179\
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\174\ Energy efficiency programs are driven by a variety of
state policies including energy efficiency resource standards,
requirements to acquire all cost-effective energy efficiency,
integrated resource planning requirements, and demand-side
management plans and budgets. Funding for energy efficiency programs
is provided through a variety of mechanisms as well, including per
kilowatt-hour surcharges and proceeds from forward capacity market
and emission allowance auctions. The programs are implemented by a
range of entities including investor-owned, municipal, and
cooperative electric utilities, state agencies, and designated
third-party administrators. All end-use sectors (residential,
commercial, and industrial) are targeted by energy efficiency
programs and numerous strategies are employed, including targeted
rebates for high-efficiency appliances; energy audits with
recommendations for cost-effective, energy-saving upgrades; and
processes to certify energy efficiency service providers.
\175\ See the appendix to the State Plan Considerations TSD for
descriptions of the full array of demand-side energy efficiency
policies currently employed by states.
\176\ EERS establish specific, long-term targets for energy
savings that utilities or non-utility program administrators must
meet through customer energy efficiency programs. EERS, as well as
requirements that utilities acquire all cost-effective energy
efficiency, have been the most impactful state energy efficiency
strategies in recent years.
\177\ The historical data used are reported to the Energy
Information Administration through Form EIA-861. The analysis and
summary of state energy efficiency policies is from the American
Council for an Energy-Efficient Economy (ACEEE), State EERS Activity
Policy Brief (February 24, 2014). See the Greenhouse Gas Abatement
Measures TSD for more information.
\178\ E.g., energy efficiency programs operated by municipal and
cooperative utilities may report their program results to their
Boards of Directors rather than to a state utility commission.
\179\ See the EM&V section of the State Plan TSD for more
information on EE program evaluation.
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While EM&V data reflect documented electricity savings from energy
efficiency programs, they typically do not account for potential
electricity savings available from additional state-implemented
policies for which EM&V protocols are less consistently required or
applied, such as building energy codes. Thus, we consider the 1.5
percent annual incremental savings \180\ rate to be a reasonable
estimate of the energy efficiency policy performance that is already
achieved or required by leading states and that can be achieved at
reasonable costs by all states given adequate time. If we were to
capture the potential for additional policies, such as the adoption and
enforcement of state or local building energy codes, to contribute
additional reductions in electricity demand beyond those resulting from
energy efficiency programs, we could reasonably increase the targeted
annual incremental savings rate beyond 1.5 percent.
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\180\ This incremental savings rate and all others discussed in
this subsection represent net, rather than gross, energy savings.
Gross savings are the changes in energy use (MWh) that result
directly from program-related actions taken by program participants,
regardless of why they participated in a program. Net savings refer
to the changes in energy use that are directly attributable to a
particular energy efficiency program after accounting for free-
ridership, spillover, and other factors.
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For states where EE program experience is more limited, reaching a
best-practices level of performance requires undertaking a set of
activities that takes some time to plan, implement, and evaluate. For
the best practices scenario, we have therefore estimated that each
state's annual incremental savings rate increases from its 2012 annual
saving rate \181\ to a rate of 1.5 percent over a period of years
starting in 2017. (Thus, the goal for each state differs to reflect the
assumption that in a state already close to a 1.5 percent annual
incremental savings rate, energy efficiency programs can be expanded to
reach that rate sooner than in a state that is further from that rate.)
The pace at which states are estimated to increase their savings rate
level is 0.2 percent per year. This rate is consistent with past
performance and future requirements of leading states.\182\ For states
already at or above the 1.5 percent
[[Page 34873]]
annual incremental savings rate (based on 2012 reported data), we
estimate that they would realize a 1.5 percent rate in 2017 and
maintain that rate through 2029. For all states we assume the initial
savings rate (the lower of their 2012 value or 1.5 percent) is realized
in 2017 and increases each year by 0.2 percent until the target rate of
1.5 percent is achieved \183\ and is then maintained at that level
through 2029. The savings from energy efficiency programs are
cumulative, meaning that, in simplified terms, a state in which a
sustained program is implemented with a 1.5 percent annual incremental
savings rate could expect cumulative annual savings of approximately
1.5 percent after the first year, 3.0 percent after the second year,
4.5 percent after the third year, and so on. Savings from the first
year would drop off at the end of the average life of the energy
efficiency program portfolio (typically about ten years). Accordingly,
we have projected the cumulative annual savings for each state that
would be achieved for the period 2020 to 2029 based on the state's
reaching and then sustaining the best practices annual incremental
savings rate through 2029. These values, for each state and for each
year (2020-2029), are used in the procedure for computing the state
goals described in Section VII.C below.
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\181\ 2012 is the most recent year for energy efficiency program
incremental savings data reported using EIA Form 861.
\182\ See the Greenhouse Gas Abatement Measures TSD for more
information.
\183\ For example, a state with a reported savings rate of 0.5%
in 2012 is assumed to realize a 2017 savings rate of 0.5% and their
savings rates for 2018, 2019, 2020, 2021 and 2022 are calculated to
be 0.7%, 0.9%, 1.1%, 1.3%, and 1.5%, respectively. By this method,
all states have reached the 1.5% target rate by 2017 at the earliest
and by 2025 at the latest.
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As discussed in Section VII.E below, the EPA is also taking comment
on a less stringent alternative for setting state goals. Under this
alternative, the demand-side energy efficiency requirement uses 1.0
percent (rather than 1.5 percent) annual incremental savings as
representative of the best-practices level of performance. In addition,
the pace at which incremental savings levels are increased from their
historical levels is relaxed slightly to 0.15 percent per year (rather
than 0.2 percent). The 1.0 percent rate of savings is a level of
performance that has been achieved--or that established state
requirements will cause to be achieved--by 20 states.\184\ As is done
with the more stringent goal-setting approach for energy efficiency,
the cumulative percentages for each state are derived and multiplied by
the state's 2012 historical electricity sales as reflected in the EIA
detailed state data, in this case for the period from 2020 to 2024.
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\184\ See the Greenhouse Gas Abatement Measures TSD for more
information.
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The state-specific cumulative annual electricity saving data inputs
for both the proposed approach and the less stringent alternative are
discussed in the Greenhouse Gas Abatement Measures TSD and summarized
in Table 7.
Table 7--Demand-Side Energy Efficiency State Goal Development: Cumulative Annual Electricity Savings (Percentage
of Annual Sales) Resulting From Best Practices Scenario \185\
----------------------------------------------------------------------------------------------------------------
1.5% Savings target scenario 1.0% Savings target scenario
State ---------------------------------------------------------------
2020 2029 2020 2024
----------------------------------------------------------------------------------------------------------------
Alabama......................................... 1.4 9.5 1.1 3.9
Alaska.......................................... 1.2 9.5 0.9 3.7
Arizona......................................... 5.2 11.4 3.5 6.0
Arkansas........................................ 1.5 9.7 1.2 4.1
California...................................... 5.0 11.6 3.6 6.1
Colorado........................................ 3.9 11.0 3.3 5.9
Connecticut..................................... 4.7 11.9 3.6 6.3
Delaware........................................ 1.1 9.5 0.9 3.6
Florida......................................... 2.0 10.0 1.8 4.7
Georgia......................................... 1.8 9.8 1.5 4.4
Hawaii.......................................... 1.3 9.5 1.0 3.8
Idaho........................................... 3.8 11.1 3.5 5.9
Illinois........................................ 4.4 11.6 3.5 6.2
Indiana......................................... 3.2 11.1 2.9 5.7
Iowa............................................ 4.7 11.7 3.6 6.0
Kansas.......................................... 1.2 9.5 0.9 3.7
Kentucky........................................ 1.9 10.0 1.6 4.6
Louisiana....................................... 1.1 9.3 0.9 3.6
Maine........................................... 5.4 12.1 3.6 6.3
Maryland........................................ 4.2 11.5 3.5 6.1
Massachusetts................................... 4.4 11.8 3.6 6.2
Michigan........................................ 4.6 11.8 3.6 6.2
Minnesota....................................... 4.8 11.7 3.6 6.2
Mississippi..................................... 1.4 9.6 1.1 3.9
Missouri........................................ 1.6 9.9 1.3 4.2
Montana......................................... 3.4 10.9 3.0 5.7
Nebraska........................................ 2.2 10.4 1.9 4.9
Nevada.......................................... 3.0 10.7 2.7 5.5
New Hampshire................................... 2.8 11.0 2.6 5.5
New Jersey...................................... 1.3 9.6 1.0 3.7
New Mexico...................................... 3.1 10.6 2.8 5.5
New York........................................ 4.4 11.8 3.5 6.2
North Carolina.................................. 2.4 10.3 2.1 5.0
North Dakota.................................... 1.4 9.7 1.1 4.0
Ohio............................................ 4.2 11.6 3.5 6.1
Oklahoma........................................ 1.9 10.0 1.6 4.5
Oregon.......................................... 4.7 11.4 3.6 6.1
Pennsylvania.................................... 4.7 11.7 3.6 6.2
[[Page 34874]]
Rhode Island.................................... 3.9 11.6 3.4 6.1
South Carolina.................................. 2.3 10.2 2.0 4.9
South Dakota.................................... 1.6 9.9 1.3 4.2
Tennessee....................................... 2.2 10.3 1.9 4.9
Texas........................................... 1.8 9.9 1.5 4.4
Utah............................................ 3.6 11.0 3.2 5.8
Virginia........................................ 1.2 9.3 1.0 3.7
Washington...................................... 4.2 11.3 3.5 6.0
West Virginia................................... 1.8 10.1 1.5 4.4
Wisconsin....................................... 4.7 11.8 3.6 6.2
Wyoming......................................... 1.6 9.7 1.3 4.2
----------------------------------------------------------------------------------------------------------------
c. Costs of Demand-Side Energy Efficiency
The EPA expects implementation of demand-side energy efficiency
policies as reflected in the best practices scenario to be achievable
at reasonable costs. The EPA finds support for the reasonableness of
the costs of this building block from two perspectives. First, the
specific savings levels represented by this building block were
developed based upon the experience and success of states in developing
and implementing energy efficiency policies that they undertake
primarily for the purpose of providing economic benefits to electricity
consumers in their state. Secondly, even with notably conservative
assumptions about the costs of achieving the levels of electricity
savings associated with this building block, the EPA's analysis of the
power sector indicates that the costs are reasonable.
The processes by which states develop funding for energy efficiency
programs typically require the application of cost-effectiveness tests
to ensure that adopted program portfolios lead to lower costs than the
use of generation sources that would otherwise be required to meet the
associated electricity service demands. Indeed, a major reason for the
widespread presence and rapid growth of demand-side energy efficiency
programs is the strong evidence of the reasonableness of their costs
even before the additional benefit of CO2 reductions is
considered.\186\ Independent studies have found that end-users' needs
for energy-dependent services (e.g., heating, cooling, lighting, motor
output, and information and entertainment services) frequently can be
satisfied at lower cost by improving the efficiency of electricity
consumption rather than by increasing the supply of electricity.\187\
These factors indicate that the cost of CO2 reductions
achieved through implementation of demand-side energy efficiency at the
levels reflected in the best practices scenario are likely to be very
reasonable, typically resulting in reductions in average electricity
bills across all end-use sectors.\188\ Because demand-side energy
efficiency costs are incurred at the time of investment, while the cost
savings (from lower electricity usage) are realized over the life of
these investments (typically about 10 years), bill reductions are
greater in later years, but provide substantial payback over the
investment period.
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\185\ Vermont and the District of Columbia are excluded from
this table because we are not proposing goals for those
jurisdictions.
\186\ Some states do include a valuation of CO2
benefits as part of their evaluations of cost effectiveness.
\187\ E.g., Electric Power Research Institute, U.S. Energy
Efficiency Potential Through 2035 (Final Report, April 2014);
Northwest Power and Conservation Council, Sixth Northwest
Conservation and Electric Power Plan (Feb. 2010), available at
http://www.nwcouncil.org/energy/powerplan/6/plan/.
\188\ As described below and in the Goal Computation TSD, in the
case of a state that is a net importer of electricity, the proposed
goal computation procedure includes an adjustment to account for the
possibility that some of the generation and emissions avoided due to
the state's demand-side energy efficiency programs may occur at EGUs
in other states. Given the extremely low cost of CO2
emission reductions achievable through demand-side energy efficiency
programs, implementation of such programs is likely to reduce
CO2 emissions at reasonable cost even for a state whose
own affected EGUs achieve only part of the CO2 emission
reduction benefit from the state's demand-side energy efficiency
efforts.
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Another approach to evaluating the reasonableness of the costs
associated with this building block is to compare the demand-side
energy efficiency costs to the avoided power system costs as
represented within the EPA's modeling of the power sector. The costs
associated with the best practices scenario were estimated based upon a
synthesis of data and analysis of the factors that impact energy
efficiency program costs as calculated using an engineering-based,
bottom-up approach that is standard for state and utility analysis of
these policies. These factors include the average energy efficiency
program costs per unit of first-year energy savings ($/MWh), the ratio
of program to participant costs, and the lifetimes of energy efficiency
measures across the full portfolio of programs. In addition, the EPA
has included a cost escalation factor to represent the possibility of
increased costs associated with higher levels of incremental energy
savings rates and the national scope of the best practices scenario.
The EPA has taken a conservative approach to each of these factors,
selecting values that are at the higher-cost end of reasonable ranges
of estimated values. The combination of these factors is reflected in
the value the EPA has derived for the levelized cost per MWh of saved
energy. This value includes both the program costs paid by utilities
for implementing energy efficiency programs and the amounts that
program participants pay for their own energy efficiency improvements
beyond the program costs. These costs are levelized across the measure
lifetimes of a full portfolio of energy efficiency programs. This
analysis provides a levelized cost of saved energy (LCOSE) range of
$85/MWh to $90/MWh ($2011) over the 2020 to 2030 period. This range of
LCOSE is notably conservative (leading to higher costs) in comparison
with most utility and state analysis. For example, a 2014 analysis by
the American Council for an Energy-Efficient Economy (ACEEE) surveyed
program and participant cost results across seven states and found a
comparable LCOSE value of $54/MWh (2011$).\189\
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\189\ American Council for an Energy-Efficient Economy (ACEEE),
The Best Value for America's Energy Dollar: A National Review of the
Cost of Utility Energy Efficiency Programs (Report No. U1402, March
2014).
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[[Page 34875]]
To estimate the reductions in power system costs and CO2
emissions associated with the best-practices level of demand-side
energy efficiency described above, the EPA analyzed a scenario
incorporating the resulting reduction in electricity demand and
compared the results with the business-as-usual scenario. Both analyses
were conducted using the Integrated Planning Model (IPM) described
previously. Combining the resulting power system cost reductions with
the energy efficiency cost estimates associated with the best practices
scenario, the EPA derived net cost impacts for 2020, 2025, and 2030.
Dividing these net cost impacts by the associated CO2
reductions for each year, the EPA found that the average cost of the
CO2 reductions achieved ranged from $16 to $24 per metric
ton of CO2. The EPA views these estimated costs as
reasonable. Together with the history of demonstrated successful state
implementation of demand-side energy efficiency programs at reasonable
costs discussed above, this analysis supports the reasonableness of the
level of demand-side energy efficiency represented by the best
practices scenario and, by extension, the reasonableness of the
emission reductions at affected EGUs that can be achieved consistent
with achievement of that level of demand-side energy efficiency.
Further details regarding the data and methodology used to evaluate
the potential for demand-side energy efficiency programs to substitute
for generation at affected EGUs and thereby facilitate reductions of
power sector CO2 emissions at reasonable costs are provided
in the Greenhouse Gas Abatement Measures TSD. We invite comment on all
aspects of our data and methodology as discussed above and in the TSD,
as well as on the level of reductions we propose to define as best
practices suitable for representation consistent with the best system
of emission reduction and the level reflected in the less stringent
scenario. We also specifically invite comment on several issues: (1)
Increasing the annual incremental savings rate to 2.0 percent and the
pace of improvement to 0.25 percent per year to reflect an estimate of
the additional electricity savings achievable from state policies not
reflected in the 1.5 percent rate and the 0.20 percent per year pace of
improvement, such as building energy codes and state appliance
standards, (2) alternative approaches and/or data sources (i.e., other
than EIA Form 861) for determining each state's current level of annual
incremental electricity savings, and (3) alternative approaches and/or
data sources for evaluating costs associated with implementation of
state demand-side energy efficiency policies.
5. Potential Emission Reduction Measures Not Used To Set Proposed Goals
There are four additional potential measures for reducing, or
supporting reduced, GHG emissions from EGUs that the EPA does not
propose to consider part of the best system of emission reduction
adequately demonstrated for existing EGUs at this time and therefore
has not used for goal-setting purposes, but that merit discussion here:
Fuel switching at individual EGUs, carbon capture and storage (CCS),
using expanded amounts of less carbon-intensive new NGCC capacity to
provide replacement generation, and heat rate improvements at affected
EGUs other than coal-fired steam EGUs.
a. Fuel Switching at Individual Units
One technically feasible approach for reducing CO2
emissions per MWh of generation from an EGU designed for coal-fired
generation is to substitute natural gas for some or all of the coal.
Most existing coal-fired steam EGU boilers can be modified to switch to
100 percent gas input or to co-fire gas with coal in any desired
proportion. For certain individual EGUs, switching to or co-firing with
gas may be an attractive option for reducing CO2 emissions.
Changing the type of fuel burned at a steam EGU typically requires
certain plant modifications (e.g., new burners) and may have some
negative impact on the net efficiencies of the boiler and the overall
generation process. If the plant lacks existing gas pipeline
infrastructure capable of delivering the necessary quantities of
natural gas to the boiler, installation of a new pipeline lateral would
also be required.
The capital costs of plant modifications required to switch a coal-
fired EGU completely to natural gas are roughly $100-300/kW, excluding
pipeline costs. For plants that require additional pipeline capacity,
the capital cost of constructing new pipeline laterals is approximately
$1 million per mile of pipeline built. Offsetting these capital costs,
conversion to 100 percent gas input would typically reduce the EGU's
fixed operating and maintenance costs by about 33 percent due mainly to
certain equipment retirements and a reduction in staffing, while non-
fuel variable costs would be reduced by about 25 percent due to reduced
maintenance and waste disposal costs. However, in most cases, the most
significant cost change associated with switching from coal to gas in a
coal-fired boiler is likely to be the difference in fuel cost. Using
EIA's projections of future coal and natural gas prices, switching a
steam EGU's fuel from coal to gas typically would more than double the
EGU's fuel cost per MWh of generation.
The CO2 reduction potential of natural gas co-firing or
conversion is due largely to the different carbon intensities of coal
and natural gas and is directly related to the proportion of gas
burned. Greater reductions in the CO2 emission rate are
achieved at higher proportions of gas usage. For example, at ten
percent gas co-firing, the net emission rate (e.g., pounds of
CO2 per net MWh of generation) of a typical steam EGU
previously burning only coal would decrease by approximately four
percent. At 100 percent gas burn, the net emission rate of a typical
steam EGU previously burning only coal would decrease by approximately
40 percent.
For a typical base-load coal-fired EGU, and reflecting EIA's
projected future natural gas and coal prices, the average cost of
CO2 reductions achieved through gas conversion or co-firing
ranges from $83 per metric ton to $150 per metric ton. The low end of
the range of CO2 reduction costs represents a 100 percent
switch to gas, because in instances where a combination of coal and gas
is burned, the EGU would continue to bear the fixed costs associated
with equipment needed for coal combustion, raising the cost per ton of
CO2 reduced.
The EPA's economic analysis suggests that there are more cost
effective opportunities for coal-fired utility boilers to reduce their
CO2 emissions than through natural gas conversion or co-
firing. As a result, the EPA has not proposed at this time to include
this option in the BSER and has not incorporated implementation of the
option into the proposed state goals. However, the EPA believes that
there are a number of factors that warrant further consideration in
determining whether the option should be included. First, the EPA is
aware that a number of utilities have reworked some of their coal-fired
units to allow for some level of natural gas co-firing (and in some
cases have converted the units to fire entirely on natural gas).
Second, the EPA is aware of several possible reasons beyond reduction
of CO2 emissions that may make natural gas co-firing
economically attractive in some circumstances. One example is that
natural gas reburn strategies that involve
[[Page 34876]]
co-firing with 10 to 20 percent natural gas can be an effective control
strategy for NOX emissions and, thus, can offset operational
(and in some cases, capital) costs associated with other NOX
controls such as selective catalytic reduction (SCR) or selective non-
catalytic reduction (SNCR). A second example suggested by some vendors
is that the capability to burn natural gas in a coal-fired boiler can
improve economics because it allows the boiler to operate more
effectively at lower loads. A third example, applicable to units that
run infrequently but may be needed for reliability purposes, is that
converting to or co-firing with natural gas may be more economically
attractive than either installing non-CO2 emission controls
or taking other measures, such as transmission upgrades, that could
become necessary if the unit were retired. Finally, beyond the reasons
just described explaining why EGU owners may find natural gas co-firing
to be cost-effective, there are also potentially significant health co-
benefits associated with burning natural gas instead of coal.
We solicit comment on whether natural gas co-firing or conversion
should be part of the BSER. We also request comment regarding whether,
and, if so, how, we should consider the co-benefits of natural gas co-
firing in making that determination.
b. Carbon Capture and Storage
Another possible approach for reducing CO2 emissions
from existing fossil fuel-fired EGUs is through the application of
carbon capture and storage \190\ technology (CCS). In the recently
proposed standards of performance for new fossil fuel-fired EGUs (79 FR
1430), the EPA proposed to find that the best system of emission
reduction for new fossil fuel-fired boilers and IGCC units is partial
application of CCS. In that proposal, the EPA found that, for new
units, partial CCS has been adequately demonstrated, it is technically
feasible, it can be implemented at costs that are not unreasonable, it
provides meaningful emission reductions, and its implementation will
serve to promote further development and deployment of the technology.
The EPA also noted in the proposal that most of the relatively few new
boiler and IGCC EGU projects currently under development are already
planning to implement CCS, and, as a result, the proposed standard
would not have a significant impact on nationwide energy prices.
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\190\ This is also sometimes referred to as ``carbon capture and
sequestration.''
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In contrast, the EPA did not identify full or partial CCS as the
BSER for new natural gas-fired stationary combustion turbines, noting
technical challenges to implementation of CCS at NGCC units as compared
to implementation at new solid fossil fuel-fired sources. The EPA also
noted that, because virtually all new fossil fuel-fired power projects
are projected to use NGCC technology, requiring full or partial CCS
would have a greater impact on the price of electricity than requiring
CCS at the few projected coal plants, and the larger number of NGCC
projects would make a CCS requirement difficult to implement in the
short term.
Partial CCS has been demonstrated at existing EGUs. It has been
demonstrated at a pilot-scale at Southern Company's Plant Barry, it is
being installed for large-scale demonstration at NRG's W.A. Parish
facility, and it is expected soon to be applied at a commercial scale
as a retrofit at SaskPower's Boundary Dam plant in Canada. However, the
EPA expects that the costs of integrating a retrofit CCS system into an
existing facility would be substantial. For example, some existing
sources have a limited footprint and may not have the land available to
add a CCS system. Moreover, there are a large number of existing
fossil-fired EGUs. Accordingly, the overall costs of requiring CCS
would be substantial and would affect the nationwide cost and supply of
electricity on a national basis.
For the reasons just described, based on the information available
at this time, the EPA does not propose to find that CCS is a component
of the best system of emission reduction for CO2 emissions
from existing fossil fuel-fired EGUs. The EPA does solicit comment on
all aspects of applying CCS to existing fossil fuel-fired EGUs (in
either full or partial configurations), but does not expect to finalize
CCS as a component of the BSER in this rulemaking. It should be noted,
however, that in light of the fact that several existing fossil-fired
EGUs are currently being retrofitted with CCS, the implementation of
partial CCS may be a viable GHG mitigation option at some facilities,
and as a result, emission reductions achieved through use of the
technology could be used to help meet the emission performance level
required under a state plan.
Additional discussion can be found in the Greenhouse Gas Abatement
Measures TSD.
c. New NGCC Capacity
In Section VI.C.2 above, we discussed the opportunity to reduce
CO2 emissions by replacing generation at high carbon-
intensity affected EGUs with lower-carbon generation from existing NGCC
units.\191\ From a technical perspective, the same potential would
exist to replace high-emitting generation with generation from
additional NGCC capacity that may be built in the future; the analysis
above regarding the feasibility of policies to increase utilization
rates of existing NGCC units on average to 70 percent applies equally
to new NGCC units.\192\ We view the opportunity to reduce
CO2 emissions at affected EGUs by means of addition and
operation of new NGCC capacity as clearly feasible.
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\191\ For purposes of this proposal, NGCC units that have
commenced construction as of January 8, 2014 are ``existing'' units.
\192\ Whether and to what extent adding new NGCC capacity is
likely to lead to CO2 reductions depends on what
incentives would exist to operate that new capacity in preference to
operation of more carbon-intensive existing EGUs. Because the
proposed state goals also reflect the opportunity to reduce
utilization of high carbon-intensity EGUs by shifting generation to
less carbon-intensive EGUs, we believe that in the context of a
comprehensive state plan, the necessary incentives would likely
exist, in which case adding new NGCC capacity would tend to reduce
CO2 emissions.
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In addition, we note that our compliance modeling for this proposal
suggests that the construction and operation of new NGCC capacity will
be undertaken as method of responding to the proposal's requirements.
However, compared to the opportunity to reduce CO2
emissions at affected EGUs by means of re-dispatch to existing NGCC
capacity, the parallel opportunity involving new NGCC capacity would be
more costly for several reasons. The first reason is the additional
cost associated with additional usage of natural gas. As noted in the
discussion of building block 2 above, the EPA analyzed costs associated
with several different target utilization rates for existing NGCC units
and that analysis showed higher costs of CO2 reductions at
higher target NGCC utilization rates.
The second reason that emission reductions from the use of new NGCC
capacity would be more costly is that there would be capital investment
costs. Some amount of new NGCC capacity (beyond the units that were
already under construction as of January 8, 2014 and are ``existing''
units for purposes of this proposal) would likely be built to meet
perceived electricity market demand or to replace less economic
capacity regardless of this proposal. The costs of achieving
CO2 emission reductions through re-dispatch to these new
NGCC units and through re-dispatch to existing NGCC units would be
comparable (ignoring consideration
[[Page 34877]]
of the cost impacts just discussed related to increases in overall gas
usage). However, in the case of any new NGCC units that would not have
been built if not for this proposal, and that were built in part for
the purpose of achieving CO2 reductions at affected EGUs,
some portion of their construction or fixed operating costs would also
be attributable to the CO2 reduction opportunity, increasing
to some extent the cost of the CO2 reductions at affected
EGUs achieved through re-dispatch to those new NGCC units.
The third reason relates to the costs of pipeline infrastructure
expansion, and in particular the unevenly distributed nature of those
costs. While expanded use of existing NGCC capacity to achieve
CO2 emission reductions can be expected to rely largely on
existing pipeline infrastructure with incremental capacity expansions,
use of new NGCC capacity--if required in all states--could require
substantially greater pipeline infrastructure investments to serve some
states than others.
Taken together, the EPA believes the cost considerations just
described indicate a higher cost for CO2 reductions
achievable from re-dispatch to new NGCC capacity than from other
options, at least for states with limited natural gas pipeline
infrastructure, and we therefore do not propose to include this option
in state goals.
While the EPA is not proposing that new NGCC capacity is part of
the basis supporting the BSER, we recognize that there are a number of
new NGCC units being proposed and that many modeling efforts suggest
that development of new NGCC capacity would likely be used as a
CO2 emission mitigation strategy. Therefore, we invite
comment on whether we should consider construction and use of new NGCC
capacity as part of the basis supporting the BSER. Further, we take
comment on ways to define appropriate state-level goals based on
consideration of new NGCC capacity.
d. Assessment of Heat Rate Improvement Opportunities at Oil-Fired Steam
EGUs, Gas-Fired Steam EGUs, NGCC Units, and Simple-Cycle Combustion
Turbine Units
The EPA assessed opportunities to improve heat rates at affected
EGUs other than coal-fired steam units. This assessment, which is
documented in a Technical Memorandum included as an appendix to the GHG
Abatement Measures TSD, considers the potential extent of heat rate
improvements and CO2 reductions that could be reasonably
available from oil-fired steam EGUs, gas-fired steam EGUs, NGCC units,
and simple-cycle combustion turbine units. For these non-coal
technologies, the total additional potential CO2 reductions
achievable through heat rate improvements appear relatively small
compared to the potential CO2 reductions achievable through
heat rate improvements at coal-fired steam EGUs. For this reason, the
EPA does not propose to include heat rate improvement opportunities at
these other fossil fuel-fired units as an element of the BSER for
CO2 emissions from affected EGUs at this time. However, we
are aware that the proportion of total generation provided from EGUs
such as oil-fired steam EGUs or gas-fired steam EGUs varies by
location, and may be relatively large in geographically isolated areas
such as islands. We therefore invite comment on whether heat rate
improvements for some of the EGU types discussed above should be
identified as a basis for supporting the BSER, with particular
reference to U.S. territories.
Finally, the EPA expects that for some individual oil/gas-fired
steam EGUs and NGCC units attractive heat rate improvement
opportunities will exist. We note that under the proposed flexible
approach to state plans described later in this preamble,
CO2 reductions achieved through such opportunities could be
used to help meet state goals, regardless of whether these measures are
used as a basis to support the BSER.
D. Potential Combinations of the Building Blocks as Components of the
Best System of Emission Reduction
This subsection summarizes the EPA's examination of combinations of
the building blocks as components of the BSER, comparing the merits of
a potential BSER that comprises only building blocks 1 and 2 with the
merits of a BSER that comprises all four building blocks--the preferred
option in this proposal. (A more detailed discussion of how we
evaluated each option against the criteria to be considered for the
BSER follows in Section VI.E.) \193\
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\193\ For convenience, the discussion in this Section VI.D is
based on our proposal to identify the BSER as consisting of the
building blocks themselves. The points made in this discussion are
also relevant for our alternative proposal to identify the BSER as
consisting of building block 1 coupled with reduced utilization of
the affected EGUs in specified amounts.
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1. Reasons for Considering Combinations of Building Blocks
As previously described, the building blocks can be summarized as
follows:
Building block 1: Reducing the carbon intensity of generation at
individual affected EGUs through heat rate improvements.
Building block 2: Reducing emissions from the most carbon-intensive
affected EGUs in the amount that results from substituting generation
at those EGUs with generation from less carbon-intensive affected EGUs
(including NGCC units under construction).
Building block 3: Reducing emissions from affected EGUs in the
amount that results from substituting generation at those EGUs with
expanded low- or zero-carbon generation.
Building block 4: Reducing emissions from affected EGUs in the
amount that results from the use of demand-side energy efficiency that
reduces the amount of generation required.
The EPA initially considered a BSER comprising only strategies
within building block 1. As described earlier in Section VI.B, the EPA
concluded that certain strategies within building block 1--specifically
heat rate improvements at individual coal-fired steam EGUs--should be a
component of the BSER determination, as they are technically feasible
and can be implemented at a reasonable cost. However, the EPA further
concluded that, while heat rate improvements qualify as a system of
emission reduction, they are not in themselves the BSER as there are
additional strategies that can be utilized in combination with building
block 1 that are technically feasible, can be implemented at reasonable
cost, and result in greater emission reductions than would be achieved
through building block 1 strategies alone. The EPA is also concerned
that if the measures that improve heat rates at coal-fired steam EGUs
in building block 1 are implemented in isolation, without additional
measures that reduce overall electricity demand or encourage
substitution of less carbon-intensive generation for more carbon-
intensive generation, the resulting increased efficiency of coal-fired
steam units would provide incentives to operate those EGUs more,
leading to smaller overall reductions in CO2 emissions.
Further, in listening sessions and other outreach meetings, the EPA
learned that states and other sources were already implementing and
pursuing strategies in the other building blocks for the purpose, at
least in part, of reducing CO2 emissions.
2. A Combination of Building Blocks 1 and 2 as the Best System of
Emission Reduction
We considered a BSER that comprises strategies from building blocks
1 and 2.
[[Page 34878]]
In this system, emission reductions at the most carbon-intensive
individual affected EGUs would occur through a combination of heat rate
improvements (resulting in a decrease in emission rates) and
substitution of generation at less carbon-intensive affected EGUs,
notably existing NGCC units. One reason for considering a BSER
comprising these two building blocks is that it involves only affected
EGUs and generation from affected EGUs.
The EPA believes that the combination of building blocks 1 and 2
would be a ``system of emission reduction'' capable of achieving
significant reductions in CO2 emissions from affected EGUs
at a reasonable cost. As discussed in Section VI.C above, each of the
two building blocks independently would be capable of achieving
meaningful CO2 emission reductions at reasonable costs. In
combination, the need to achieve the level of emission reductions
achievable through use of building block 2 can mitigate the concern
that building block 1, implemented alone, would make coal-fired EGUs
more economically competitive and lead to increased generation that
would offset the emission reduction benefits of the carbon-intensity
improvements. While combining the building blocks may also raise the
cost per ton of emission reductions achieved through heat rate
improvements (by reducing the quantity of MWh generated from the EGUs
with improved heat rates and therefore also reducing the aggregate
emission reductions achieved at those EGUs by the heat rate
improvements), the costs of heat rate improvements are low enough that
we believe their cost per ton of emission reduction would remain
reasonable.
Nevertheless, the EPA is not proposing that a combination of
building blocks 1 and 2 is the BSER, because the proposed combination
of all four building blocks discussed below--in other words, adding to
the measures in building blocks 1 and 2 the measures in building blocks
3 and 4, which we and stakeholders have identified as already in use--
is capable of achieving even greater CO2 emission reductions
from affected EGUs at reasonable costs. The state-specific goals that
would be computed consistent with a BSER based on the combination of
only building blocks 1 and 2 (i.e., goals computed using the goal
computation methodology discussed in Section VII below, except for the
omission of building blocks 3 and 4) are presented in the Goal
Computation TSD available in the docket. Further information on the
EPA's evaluation of this combination is available in the ``Analysis of
Emission Reductions, Costs, Benefits and Economic Impacts Associated
with Building Blocks 1 and 2'' available in the docket. We invite
comment on a potential BSER comprising a combination of building blocks
1 and 2.
3. A Combination of all Four Building Blocks as the Best System of
Emission Reduction
Our proposal for the BSER is a combination of all four building
blocks. As discussed in Section VI.C above, each of the four building
blocks is a proven way to support either improvements in emissions
rates at affected EGUs or reductions in EGU mass emissions; each is in
widespread use and is independently capable of supporting significant
CO2 reductions from affected EGUs, either on an emission
rate or mass-emissions basis, at a reasonable cost consistent with
ensuring system reliability. As discussed in Section VI.E below, the
combination of all four building blocks provides the basis for
satisfying the legal criteria to be considered the BSER. Further, as
discussed in Section X below, the combination of all four building
blocks can achieve greater overall CO2 emission reductions
from affected EGUs, at a lower cost per unit of CO2
eliminated, than the combination of building blocks 1 and 2.
In the large and highly integrated electricity system, where
electricity is fungible and the demand for electricity services can be
met in many ways (including through demand-side energy efficiency),
states and the industry have long pursued a wide variety of strategies
for ensuring that the demand for electricity services is met reliably,
at reasonable costs, and in a manner consistent with evolving
constraints, including environmental objectives. These strategies have
long extended to the measures in all four building blocks. We believe
the combination of all four building blocks fairly represents the range
of measures that states and the industry will consider when developing
state plans and strategies for reducing CO2 emissions from
affected EGUs while continuing to meet demand for electricity services
reliably and affordably. Therefore, we believe it is appropriate to
consider that same combination as the BSER upon which the required
CO2 standards of performance for affected EGUs should be
based.
E. Determination of the Best System of Emission Reduction
1. Overview
In this section, the EPA explains the ``best system of emission
reduction . . . adequately demonstrated.'' This explanation includes
what the EPA proposes to determine as the BSER and why. In addition the
EPA explains how the BSER forms the basis for each state's overall
emission limitation requirement, which the EPA determines as the state
goal and the state adopts into its planning process as the emissions
performance level. The emission performance level, in turn, constitutes
the minimum degree of stringency for the standards of performance that,
taken as a whole, the state must establish for its affected EGUs (or,
if the state adopts the portfolio approach, for the requirements
imposed on the affected EGUs and other entities). Through this process,
the BSER informs the minimum stringency of the standards of
performance, although the state retains flexibility in its allocation
of emission limitations among its sources. As the EPA explains, central
to this overall approach is the fact that the EPA applies the BSER on a
state-wide basis, which is consistent with the interconnected nature of
the electricity system.
The EPA is proposing two alternative formulations for the BSER,
each of which is based on, although in different ways, the four
building blocks. Under the first approach, emission rate improvements
and mass emission reductions at affected EGUs facilitated through the
adoption of the four building blocks themselves meet the criteria for
the BSER because they will amount to substantial reductions in
CO2 emissions achieved while maintaining fuel diversity and
a reliable, affordable electricity supply for the United States. Under
the second approach, the BSER consists of building block 1 coupled with
reduced utilization in specified amounts from, in general, higher-
emitting affected EGUs. Under this latter approach, the measures in
building blocks 2, 3, and 4 serve to justify those amounts and the
``adequate[ ] demonstrat[ion]'' because they are proven measures that
are already being pursued by states and the industry, at least in part
for the purpose of reducing CO2 emissions from affected
EGUs.
The remainder of this discussion is organized into the following
subsections. Subsection 2 contains a summary of relevant considerations
for the BSER as defined in the statute and further interpreted in court
decisions. Subsection 3 discusses characteristics of the electricity
industry relevant to
[[Page 34879]]
interpretation of the BSER for purposes of this proposal, most notably
the industry's highly interconnected and integrated nature. Subsection
4 provides a discussion of how the building blocks would satisfy the
BSER criteria in isolation or support the alternative formulation of
the BSER as including reduced utilization in specified amounts.
Subsection 5 evaluates two combinations of building blocks--a
combination of building blocks 1 and 2, and the proposed combination of
all four building blocks--against the BSER criteria, and explains why
we propose that the combination of all four is the BSER. Subsection 6
addresses additional considerations related to the inclusion of
building blocks 2, 3, and 4 as parts of the basis supporting the BSER.
In subsection 7, we describe and seek comment on the alternate
interpretation that the BSER includes, in addition to building block 1,
a component consisting of reduced generation from higher-emitting
affected EGUs, with the measures in the other building blocks serving
as the basis for quantifying the amounts of generation reductions and
consequent CO2 emission reductions that can be achieved
while continuing to meet the demand for electricity services in a
reliable and affordable manner. In subsection 8, we discuss the
discretion that the case law gives us in weighing the various criteria
to determine the BSER. In subsection 9, we discuss how the BSER and the
state-wide manner in which the EPA applies it form the basis for the
emission standards that the state includes in the plan, and we explain
why that approach is consistent with the applicable section 111
requirements. The final three subsections address the topics of
combining source categories, severability, and certain other specific
issues on which we are seeking comment. Additional discussion is
provided in the Legal Memorandum available in the docket.
2. Statutory and Regulatory Provisions Related to Determination and
Application of the BSER
The EPA's explanation for this BSER proposal begins with the
statutory definition of a ``standard of performance'':
The term ``standard of performance'' means a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which (taking into account the cost of achieving
such reduction and any nonair quality health and environmental
impact and energy requirements) the Administrator determines has
been adequately demonstrated.
42 U.S.C. 7411(a)(1).
The U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit or
Court) has handed down case law over a 40-year period that interprets
this CAA provision, including its component elements.\194\ Under this
case law, the EPA determines the BSER based on the following key
considerations, among others:
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\194\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974); Essex Chemical Corp.
v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973), cert. denied,
Appalachian Power Co. v. EPA, 416 U.S. 969 (1974); Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981); Portland Cement Ass'n v. EPA,
665 F.3d 177 (D.C. Cir. 2011). Although this case law concerns the
meaning of the definition of ``standard of performance'' for
purposes of rulemakings that the EPA promulgated under CAA section
111(b), the same term is used for section 111(d), and as a result,
this case law is relevant for the present rulemaking under section
111(d).
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The system of emission reduction must be technically
feasible.
The EPA must consider the amount of emission reductions
that the system would generate.
The costs of the system must be reasonable. The EPA may
consider costs at the source level, the industry level, and, at least
in the case of the power sector, the national level in terms of the
overall costs of electricity and the impact on the national economy
over time.\195\
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\195\ As discussed in the January 2014 Proposal, the D.C.
Circuit's case law formulates the cost consideration in various
ways: The costs must not be ``exorbitant[ ]'', Essex Chemical Corp.
v. Ruckelshaus, 486 F.2d at 433, see Lignite Energy Council v. EPA,
198 F.3d 930, 933 (D.C. Cir. 1999); ``greater than the industry
could bear and survive,'' Portland Cement Ass'n v. EPA, 513 F.2d
506, 508 (D.C. Cir. 1975); or ``excessive'' or ``unreasonable,''
Sierra Club v. Costle, 657 F.2d at 343. In the January 2014
Proposal, the EPA stated that ``these various formulations of the
cost standard . . . are synonymous,'' and, for convenience, we used
``reasonableness'' as the formulation. We take the same approach in
this rulemaking.
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The EPA must also consider that CAA section 111 is
designed to promote the development and implementation of technology,
including the diffusion of existing technology as the BSER,\196\ the
development of new technology that may be treated as the BSER,\197\ and
the development of other emerging technology.\198\
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\196\ See 1970 Senate Committee Report No. 91-1196 at 15 (``The
maximum use of available means of preventing and controlling air
pollution is essential to the elimination of new pollution
problems'').
\197\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d at 391
(the best system of emission reduction must ``look[ ] toward what
may fairly be projected for the regulated future, rather than the
state of the art at present'').
\198\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a
standard of performance designed to promote the use of an emerging
technology).
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Another consideration particularly relevant to this rulemaking is
energy impacts, which, as with costs, the EPA may consider at the
source level, the industry level, and the national level over time. In
the context of the electricity industry and this proposal, the EPA
believes that the scope of energy impacts that may be considered
encompasses assurance of the continued ability of the industry to meet
the evolving demand for electricity services in a reliable manner,
while providing sufficient flexibility to enable affected sources to
follow state energy plans.
Importantly, the EPA has discretion to weigh these various
considerations, may determine that some merit greater weight than
others, and may vary the weighting depending on the source category.
It is a well-established principle that states have discretion
regarding the measures adopted in their state implementation plans
under CAA section 110 to attain the NAAQS.\199\ The EPA believes that
the same principle applies in the context of state plans under section
111(d) as well, such that each state has the discretion to adopt
emission reduction measures other than the measures found by the EPA to
comprise the BSER, or to place greater or lesser emphasis than the EPA
on certain measures, provided that the state's plan achieves the
required level of emission performance for affected sources.
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\199\ See Train v. Natural Res. Def. Council, 421 U.S. 60
(1975).
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The EPA discussed the CAA requirements and Court interpretations of
the BSER at length in the January 2014 Proposal, 79 FR at 1,462/1-
1,467/3, and incorporates by reference that discussion into this
rulemaking.
Over the last forty years, under CAA section 111(d), the agency has
regulated four pollutants from five source categories (i.e., phosphate
fertilizer plants (fluorides), sulfuric acid plants (acid mist),
primary aluminum plants (fluorides), Kraft pulp plants (total reduced
sulfur), and municipal solid waste landfills (landfill gases)).\200\ In
addition, the agency has regulated additional pollutants under CAA
[[Page 34880]]
section 111(d) in conjunction with CAA section 129.\201\ However, the
agency has not previously regulated CO2 or any other
greenhouse gas under CAA section 111(d) (although because landfill
gases include methane, the agency's regulation of landfill gases
reduced emissions of that greenhouse gas). Further, the electricity
industry differs in important ways from the source categories
previously regulated under section 111(d) in terms of its large scale,
its central importance to the economy, and, as discussed below, its
highly interconnected and integrated nature.
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\200\ See ``Phosphate Fertilizer Plants; Final Guideline
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards
of Performance for New Stationary Sources and Guidelines for Control
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,''
61 FR 9905 (Mar. 12, 1996).
\201\ See, e.g., ``Standards of Performance for New Stationary
Sources and Emission Guidelines for Existing Sources: Sewage Sludge
Incineration Units, Final Rule,'' 76 FR 15372 (Mar. 21, 2011).
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3. The Interconnected Nature of the U.S. Electricity Sector
The U.S. electricity system is a highly interconnected, integrated
system in which large numbers of EGUs using diverse fuels and
generating technologies are operated in a coordinated manner to produce
fungible electricity services for customers. Because electricity
storage is costly and has not been widely deployed, the amounts of
electricity demanded and supplied must be continuously matched, and
system operators typically have flexibility to choose among multiple
EGUs when selecting where to obtain the next MWh of generation needed.
Coordination over short- and long-term time scales is accomplished
through a variety of institutions including vertically integrated
utilities, state regulatory agencies, independent system operators and
regional transmission organizations (ISOs/RTOs), and market mechanisms.
The electricity sector is both critical to the nation's economy and the
source of more than 30 percent of U.S. greenhouse gas emissions,
predominantly in the form of CO2.
The integrated electricity system allows increased generation from
less carbon-intensive NGCC units to substitute for generation from more
carbon-intensive steam EGUs (building block 2), thereby lowering
CO2 emissions from the group of affected EGUs as a whole.
The electricity system similarly allows increased generation resulting
from expansion of the amount of available low- or zero-carbon
generating capacity connected to the electric grid (building block 3),
as well as avoided generation resulting from reductions in electricity
demand (building block 4), to substitute for fossil fuel-fired
generation, thereby reducing CO2 emissions from affected
EGUs. Each of these measures already routinely occurs within this
integrated system for providing electricity and electricity services.
The integrated nature of the electricity system has long played a
central role in the industry's continuing efforts to assure reliability
and to manage costs generally. Specifically in the area of pollution
control, state governments and the federal government have repeatedly
taken advantage of the integrated nature of the electricity system when
designing programs to allow the industry to meet the pollution control
objectives in a least-cost manner. Examples include several cap-and-
trade programs to reduce national or regional emissions of
SO2 and NOX: The SO2-related portion
of the CAA Title IV Acid Rain Program, the Ozone Transport Commission
(OTC) NOX Budget Program, the NOX SIP Call
NOX Budget Trading Program, and the Clean Air Interstate
Rule (CAIR) annual SO2, annual NOX, and ozone-
season NOX trading programs. While the Acid Rain Program was
created by federal legislation, the OTC NOX Budget Program
was developed primarily through the joint efforts of a group of
northeastern states. In the NOX SIP Call and CAIR programs,
the federal government set emission budgets and developed trading
programs that states could use as a compliance option.\202\ Each of
these programs was designed to take advantage of the fact that in an
integrated electricity system, some EGUs can reduce emissions at lower
costs than others, and that by allowing the industry to determine
through market mechanisms which EGUs to control and which to leave
uncontrolled, and which EGUs to potentially operate more and which to
potentially operate less, overall compliance costs can be reduced. The
integrated electricity system plays the important function of allowing
some EGUs to reduce their generation while ensuring that overall demand
for electricity services can be reliably met. It is worth noting that
adoption by affected EGUs of any of the measures in the building blocks
could be (or could have been) used to facilitate compliance with each
of the programs just described.\203\
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\202\ In the Regional Greenhouse Gas Initiative, described in
more detail below, participating states use emission budgets and a
trading program to address CO2 emissions from the
electricity sector.
\203\ In addition to the already-implemented programs mentioned
above--the SO2-related portion of the Acid Rain Program,
the OTC NOX Budget Program, the NOX SIP Call
NOX Budget Trading Program, and the Clean Air Interstate
Rule trading programs--use of measures in the building blocks would
also facilitate compliance with the cap-and-trade programs
established by the Cross-State Air Pollution Rule (76 FR 48208, Aug.
8, 2011).
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Some states are already relying on the integrated nature of the
electricity system to establish the policy contexts within which
affected EGUs will reduce their CO2 emissions.\204\
California and Colorado provide two examples of how statewide targets
(or company-wide targets within a state) can be designed with
consideration of the wide range of CO2 mitigation options
and affected EGUs' flexibility to use those options.
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\204\ A number of utilities also have climate mitigation plans.
Examples include National Grid, http://www2.nationalgrid.com/responsibility/how-were-doing/grid-data-centre/climate-change/;
Exelon, http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.aspx; PG&E, http://www.pge.com/about/environment/pge/climate/; and Austin Energy, http://austinenergy.com/wps/portal/ae/about/environment/austin-climate-protection-plan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDBzdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/.
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California enacted its Global Warming Solutions Act (also known as
AB32) in 2006, requiring the state to reduce its GHG emissions to 1990
levels by 2020 and 80 percent below 1990 levels by 2050.\205\ According
to California, ``the integrated nature of the power grid means that
policies which displace the need for fossil generation can often cut
emissions from covered sources more deeply, and more cost-effectively
than can engineering changes at the plants alone, though these source-
level control efforts are a vital starting point.'' \206\ California
therefore relied on a suite of mechanisms to provide fossil fuel-fired
generation substitutes and incentives for EGUs to reduce their
emissions, including demand-side energy efficiency programs, renewable
energy programs, and an economy-wide cap-and-trade program, along with
other programs.\207\ The California plan has put in place mechanisms
that through market dynamics affect both companies' longer-term
planning decisions and their short-term dispatch decisions. The need to
hold emissions allowances and the reduced demand from demand-side
energy efficiency programs impact longer-term decisions companies make
about investment in both existing and new EGUs. The price of emission
allowances also impacts hourly dispatch decisions; where emission
allowance requirements are in effect, EGU owners
[[Page 34881]]
routinely recognize the costs of emission allowances as components of
the variable operating costs that are relied on for these
decisions.\208\ In this manner, allowance prices constitute market
signals encouraging reduced use of higher-emitting EGUs and increased
use of lower-emitting EGUs.
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\205\ State of California Global Warming Solutions Act of 2006,
Assembly Bill 32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf.
\206\ December 27, 2013 Letter from Mary D. Nichols, Chairman of
California Air Resources Board, to EPA Administrator Gina McCarthy.
\207\ See Cal. Air Res. Bd., Climate Change Scoping Plan 31-32,
41-46 (2008), available at http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf.
\208\ The requirement to hold allowances covering their
CO2 emissions went into effect for EGUs in California on
January 1, 2013.
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The Colorado Clean Air, Clean Jobs Act (CACJA), signed into law on
April 19, 2010, required each investor-owned utility with coal-fired
EGUs to submit to the state a multi-pollutant plan for meeting current
and foreseeable EPA standards for emissions of NOX,
SO2, particulates, mercury, and CO2. Rather than
fully prescribing specific control technologies, the law provided
flexibility for each utility to select the best set of measures to
achieve the emission reductions.\209\ For example, a utility could
choose to retrofit or repower EGUs, or it could choose to retire
higher-emitting EGUs and replace them with NGCC units and other low- or
non-emitting energy plants or with end-use efficiency measures.\210\
The Colorado plan generally focused more on impacting companies'
longer-term planning decisions than on affecting short-term dispatch
decisions. In response, Colorado utilities have adopted a mix of
measures including retrofits, natural gas conversions and retirements
of coal-fired EGUs, as well as construction of new NGCC units.
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\209\ The law also set some explicit requirements, such as
requirements for development of new renewable generating capacity
and requirements to phase out older coal-fired EGUs.
\210\ See State of Colorado House Bill 10-1365, available at
http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0CA296732C8CEF4D872576E400641B74?Open&file=1365_ren.pdf.
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Multi-state mechanisms with analogous impacts on both longer-term
planning decisions and short-term dispatch decisions have also been put
in place. For example, nine northeastern and Mid-Atlantic States \211\
participate in the Regional Greenhouse Gas Initiative (RGGI), a market-
based emissions budget trading program that sets an aggregate limit on
CO2 emissions from fossil fuel-fired EGUs in the
participating states. To comply with the program, each EGU must acquire
allowances equal to its emissions in each compliance period--through
purchases or by allocation from the state--and must surrender the
allowances at the end of the period. The RGGI program offers
flexibility to regulated parties through provisions for multi-year
compliance periods, allowance banking, offsets, an auction reserve
price, and a cost-containment reserve of allowances, and further
encourages emission allowance market development by authorizing trading
between regulated and non-regulated parties.\212\ Operating in this
regime, EGUs could take a variety of compliance actions, including
replacing generation at higher-emitting EGUs with generation at lower-
emitting EGUs or achieving emissions reductions at EGUs by means of
end-use energy efficiency programs.
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\211\ Participating states include Connecticut, Delaware, Maine,
Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and
Vermont.
\212\ See RGGI Web site at http://www.rggi.org/rggi.
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An approach to determination of the BSER that recognizes the
integrated nature of the electricity system is also consistent with the
way in which the electricity industry already addresses resource
planning issues. For example, in states where the price of EGUs'
generation remains subject to regulation, utilities generally prepare
integrated resource plans setting forth their strategies for meeting
future demand for electricity services in a cost-effective manner.
These plans may include measures from building blocks 2, 3, and 4. In
most states where generation is no longer subject to price regulation,
regional transmission organizations (RTOs) or independent system
operators (ISOs) ensure the adequacy of future generation supplies by
administering auctions for forward capacity. In these auctions, owners
of existing EGUs (with consideration of building blocks 1 and 2),\213\
developers of new EGUs including renewable generating capacity
(building block 3), and developers of demand-side resources (building
block 4) all compete to provide potential resources for meeting the
projected demand for electricity services.
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\213\ Potential heat rate improvements create opportunities for
EGU owners to reduce their variable costs, which increase potential
operating profits from generation and thereby create opportunities
to lower the prices at which the owners would bid the capacity of
their EGUs into the auctions.
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As indicated by the foregoing discussion, in the U.S. electricity
system the demand for electricity services is met, on both a short-term
and longer-term basis and in both regulated and deregulated contexts,
through integrated consideration of a wide variety of possible options,
coordinated by some combination of utilities, regulators, system
operators, and market mechanisms. The EPA believes that the BSER for
CO2 emissions from existing EGUs should reflect this
integrated character.
A final, important point regarding the integrated electricity
system is that the sets of actions that enable the demand for
electricity services to be continuously met can be undertaken in
different orders, with changes in some interconnected elements
eliciting compensating responses from other interconnected elements.
Thus, the CO2 emissions reductions associated with building
blocks 2, 3, and 4 can be achieved in either of two ways: (i) First
instituting measures in building blocks 2, 3, and 4, which, due to the
interconnected and integrated nature of the grid, would elicit the
response of reducing generation at some or all affected EGUs, thereby
lowering those EGUs' emissions; or (ii) first reducing generation and
therefore emissions from some or all affected EGUs (or planning to make
those reductions), which due to the interconnected and integrated
nature of the grid, would elicit the responses identified in building
blocks 2, 3, and 4 of increasing generation at lower-emitting EGUs or
reducing the demand for electricity services. (In some cases, the
change and response could be planned simultaneously.) Each of these
sets of actions, with the building blocks as the initial change or the
reduced generation at affected EGUs as the initial change, may be
considered to be part of a ``system of emission reduction,'' as
discussed below.
Further discussion of the ways in which the ``system of emission
reduction'' for affected EGUs is influenced by the interconnected and
integrated nature of the electricity system is provided below in the
context of the EPA's rationale for proposing to base the BSER on the
combination of all four building blocks. This topic is also discussed
in the Legal Memorandum available in the docket.
4. Evaluation of Individual Building Blocks Against the BSER Criteria
In this subsection we explain why (i) the individual building
blocks meet the criteria to qualify as components of the ``best system
of emission reduction . . . adequately demonstrated'' and (ii) why,
under the alternative formulation of the BSER as including reduced
utilization of higher-emitting affected EGUs in specified amounts,
building blocks 2, 3, and 4 serve as the basis for those amounts and
why the reduced utilization is ``adequately demonstrated.''
a. Building Block 1--Heat Rate Improvements
Building block 1--reducing the carbon intensity of generation at
individual affected coal-fired steam EGUs through heat rate
improvements--is a component of the BSER because the measures the
affected sources may
[[Page 34882]]
undertake to achieve heat rate improvements are technically feasible
and of reasonable cost, and meet the other requirements to qualify as a
component of the ``best system of emission reduction . . . adequately
demonstrated.''
The EPA's analysis and conclusions regarding the technical
feasibility, costs, and magnitude of CO2 emission reductions
achievable through heat rate improvements are discussed in Section
VI.C.1 above. We consider heat rate improvement to be a common and
well-established practice within the industry.
Other BSER criteria also favor building block 1 as a component of
the BSER. For example, with respect to non-air health and environmental
impacts, heat rate improvements cause fuel to be used more efficiently,
reducing the volumes of and therefore the adverse impacts associated
with disposal of coal combustion solid waste products. With respect to
technological innovation, building block 1 encourages the spread of
more advanced technology to EGUs currently using components with older
designs. The EPA has not specifically evaluated the extent to which
enhanced maintenance practices leading to heat rate improvements might
also lead to electricity reliability improvements, but generally
expects that enhanced maintenance would be more likely to improve than
to degrade EGU availability, which would tend to improve electricity
system reliability.
As noted above, the EPA is concerned about the potential ``rebound
effect'' associated with building block 1 if applied in isolation. More
specifically, we noted that in the context of the integrated
electricity system, absent other incentives to reduce generation and
CO2 emissions from coal-fired EGUs, heat rate improvements
and consequent variable cost reductions at those EGUs would cause them
to become more competitive compared to other EGUs and increase their
generation, leading to smaller overall reductions in CO2
emissions (depending on the CO2 emission rates of the
displaced generating capacity). However, we believe that this concern
can be readily addressed by ensuring that the BSER also reflects other
CO2 reduction strategies that encourage increases in
generation from lower- or zero-carbon EGUs or in demand-side energy
efficiency, thereby allowing building block 1 to be considered part of
the BSER for CO2 emissions at affected EGUs.
b. Building Block 2--Re-Dispatch
Building block 2--reducing CO2 emissions at and
substituting for generation from the most carbon-intensive affected
EGUs with generation from less carbon-intensive affected EGUs
(specifically NGCC units that are currently operating or under
construction)--is a component of the BSER because the shifts in
generation that it involves demonstrate that reducing mass
CO2 emissions at higher-emitting EGUs is technically
feasible, will not jeopardize system reliability, is of reasonable
cost, and meets the other requirements for a component of the ``best
system of emission reduction . . . adequately demonstrated.''
The EPA's analysis and conclusions regarding the technical
feasibility, costs, and magnitude of CO2 emission reductions
achievable at high-emitting EGUs through re-dispatch among affected
EGUs are discussed in Section VI.C.2 above. We consider re-dispatch
among the large number of diverse EGUs that are linked to one another
and to customers by extensive regional transmission grids to be a
routine and well-established operating practice within the industry
that is used to facilitate the achievement of a wide variety of
objectives, including environmental objectives, while meeting the
demand for electricity services. As discussed above, in the
interconnected and integrated electricity industry, fossil fuel-fired
steam EGUs are able to reduce their generation and NGCC units are able
to increase their generation in a coordinated manner through
mechanisms--in some cases centralized and in others not--that regularly
deal with such changes on both a short-term and a longer-term basis.
Both the achievability of this building block and the
reasonableness of its costs are supported by the fact that there has
been a long-term trend in the industry away from coal-fired generation
and toward NGCC generation for a variety of reasons. As part of their
CO2 reduction strategies, states can encourage this trend in
a variety of ways. First, a state could use its permitting authority to
impose limits on the hours of operation (or emissions) of individual
steam generating units over a given time period. Second, a state could
change the relative costs of generation for more carbon-intensive and
less carbon-intensive generating units by imposing a cost on carbon
emissions. A state could do so through any of several market-based
mechanisms. One would be to adopt an allowance-based system. An example
is the Regional Greenhouse Gas Initiative, an allowance-based system in
which sources purchase allowances in periodic auctions. Another way
would be through a tradable emission rate system, under which the state
would impose an emission rate limit on the steam generating unit that
the unit could meet only by purchasing the right to average its
emission rate with a unit with a lower rate, such as an NGCC unit. Most
broadly, an allowance system would provide the greatest incentive for
the most carbon-intensive affected sources to reduce emissions as much
as possible so as to reduce their need to purchase allowances (or to
allow them to sell un-needed allowances), and the same would be true
for a tradable emission rate system.
The emission reductions achievable or supported by the application
of building block 2 also perform well against other BSER criteria. For
example, we expect that building block 2 would have positive non-air
health and environmental impacts. Coal combustion for electricity
generation produces large volumes of solid wastes that require
disposal, with some potential for adverse environmental impacts; these
wastes are not produced by natural gas combustion. The intake and
discharge of water for cooling at many EGUs also carries some potential
for adverse environmental impacts; NGCC units generally require less
cooling water than steam EGUs.\214\ As already noted, with respect to
energy impacts, the EPA believes that building block 2 (at least at the
level of stringency proposed for purposes of establishing state goals)
would not pose risks to reliability. Building block 2 also promotes
greater use of the advanced NGCC technology installed in the existing
fleet of NGCC units.
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\214\ According to a DOE/NETL study, the relative amount of
water consumption for a new pulverized coal plant is 2.5 times the
consumption for a new NGCC unit of similar size. ``Cost and
Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous
Coal and Natural Gas to Electricity,'' Rev 2a, September 2013,
National Energy Technology Laboratory Report DOE/NETL-2010/1397.
---------------------------------------------------------------------------
It should be observed that, by definition of the elements of this
building block, the shifts in generation taking place under building
block 2 occur entirely among existing EGUs subject to this
rulemaking.\215\ Through application of this building block considered
in isolation, some affected sources--mostly coal-fired steam EGUs--
would reduce their generation and CO2 emissions, while other
affected sources--NGCC units--would increase their generation and
CO2 emissions.\216\
[[Page 34883]]
However, because for each MWh of generation, NGCC units produce less
CO2 emissions than coal-fired steam EGUs, the total quantity
of CO2 emissions from all affected sources in aggregate
would decrease. In the context of the integrated electricity system,
where the operation of affected EGUs of multiple types is routinely
coordinated to provide a fungible service, and in the context of
CO2 emissions, where location is a less important factor
than is the case for other pollutants, the EPA believes that a measure
that takes advantage of that integration to reduce CO2
emissions from the overall set of affected EGUs is readily encompassed
within the meaning of a ``system of emission reduction'' for
CO2 emissions at affected EGUs even if the measure would
increase CO2 emissions from a subset of those affected EGUs.
Indeed, our review of the data and discussions with states reveal that
some states are already moving in this direction for this purpose
(while others are moving in the same direction for other purposes).
Emission trading or averaging approaches can facilitate the
implementation of such a ``system'' and have already been used in the
electricity industry to address CO2 as well as other
pollutants, as discussed above.
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\215\ For purposes of this rulemaking, ``existing'' EGUs include
units under construction as of January 8, 2014, the date of
publication in the Federal Register of the Carbon Pollution
Standards for new fossil fuel-fired EGUs.
\216\ Because building blocks 3 and 4 reduce generation and
CO2 emissions from all fossil fuel-fired affected EGUs as
a group, including NGCC units, the increase in generation and
CO2 emissions from NGCC units under building block 2 is
mitigated to some extent by including those building blocks in the
BSER along with building block 2.
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Finally, the EPA notes that the alternative interpretation of the
BSER discussed later is based in part on the re-dispatch measures in
building block 2. In this alternative, as it relates to building block
2, reduced generation from the subset of affected EGUs consisting of
fossil fuel-fired steam EGUs--i.e., the most carbon-intensive subset of
affected EGUs--is a component of the BSER. The potential to use
increased generation from less carbon-intensive affected NGCC units
would serve as a basis for quantifying the amounts of generation
reductions and CO2 emission reductions at more carbon-
intensive affected EGUs that could be achieved while continuing to meet
the demand for electricity services in a reliable and affordable
manner. This alternative is discussed further in Section VI.E.7 below.
c. Building Block 3--Use of Expanded Low- and Zero-Carbon Generating
Capacity
Building block 3--reducing CO2 emissions at and
substituting for generation from affected EGUs by using expanded
amounts of low- and zero-carbon generating capacity--is a component of
the BSER because the expansion and use of renewable generating
capacity, completion and use of nuclear capacity currently under
construction, and avoidance of nuclear capacity retirements all
establish the foundation for a determination that mass emission
reductions from affected EGUs are technically feasible, do not
jeopardize system reliability, are of reasonable cost, and meet the
other requirements for a component of the ``best system of emission
reduction . . . adequately demonstrated.''
The EPA's analysis and conclusions regarding the technical
feasibility, costs, and magnitude of the measures in building block 3
are discussed in Section VI.C.3 above. We consider all of these
measures to be proven, well-established practices within the industry,
and development of renewable capacity in particular is consistent with
recent industry trends. States are already pursuing policies that
encourage production of greater amounts of renewable energy, such as
the establishment of targets for procurement of renewable generating
capacity. Moreover, markets for renewable energy certificates, which
facilitate investment in renewable energy, are already well-
established. As noted above with re-dispatch, an allowance system or
tradable emission rate system would provide incentives for sources to
reduce their emissions as much as possible, including through
substituting for their generation with generation from renewable
energy. In addition, owners of existing nuclear units and nuclear units
currently under construction can take action to complete or preserve
that capacity, the generation from which likewise can be dispatched in
a coordinated manner to substitute for fossil fuel-fired generation. As
discussed above, coordination of these decisions in the integrated
electricity system can occur through a variety of mechanisms, some
centralized and some not.
The renewable capacity measures in building block 3 generally
perform well against other BSER criteria. For example, incentives for
expansion of renewable capacity encourage technological innovation in
improved renewable technologies as well as more extensive deployment of
current advanced technologies. Generation from wind turbines (the most
common renewable technology) does not produce solid waste or require
cooling water, a better environmental outcome than if that amount of
generation had instead been produced at a typical range of fossil fuel-
fired EGUs. Although the intermittent nature of generation from
renewable resources such as wind and solar units requires special
consideration from grid operators, renewable generation has grown
quickly in recent years, as discussed above, and the EPA has seen no
evidence that operators will be less able to cope with future growth
than they have with rapid past growth.
The EPA believes that the performance of the nuclear measures in
building block 3 against the other BSER measures is also positive on
balance. With respect to encouragement of technological innovation,
incentives for completion of nuclear capacity currently under
construction encourage deployment of nuclear unit designs that reflect
advances over earlier designs. The nation's nuclear fleet today
routinely operates at high average utilization rates, suggesting no
reason to expect adverse reliability consequences from completion or
preservation of additional nuclear capacity. The five nuclear units
currently under construction are all designed to use closed-cycle
cooling systems with lower cooling water usage than some existing
fossil fuel-fired EGUs;\217\ existing nuclear units may use amounts of
cooling water comparable to the amounts used by those fossil fuel-fired
steam EGUs. The EPA recognizes that nuclear generation poses unique
waste disposal issues (although it avoids the solid waste issues
specific to coal-fired generation). However, we do not consider that
potential disadvantage of nuclear generation relative to fossil fuel-
fired generation as outweighing nuclear generation's other advantages
as an element of building block 3. For all these reasons, we consider
building block 3 to be a component of the ``best system of emission
reduction . . . adequately demonstrated.''
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\217\ See U.S. NRC, Watts Bar Unit 2 Final Environmental
Statement, Final Report at 3-3, available at http://pbadupws.nrc.gov/docs/ML1314/ML13144A092.pdf; U.S. NRC, Summer Units
2-3 Final Environmental Impact Statement, Final Report at 3-14,
available at http://pbadupws.nrc.gov/docs/ML1109/ML11098A044.pdf;
U.S. NRC, Vogtle Units 3-4 Final Environmental Impact Statement,
Final Report at 3-5, available at http://pbadupws.nrc.gov/docs/ML0822/ML082240145.pdf. Relative to the once-through systems at many
existing power plants, closed-cycle cooling systems withdraw from
and discharge to external water bodies substantially less overall
cooling water, although they also consume larger amounts of water
through evaporation. See Department of Energy/Office of Fossil
Energy's Power Plant Water Management R&D Program, available at
http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/PowerPlantWaterMgtR-D-Final-1.pdf.
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Finally, the EPA notes that the alternative BSER discussed later
would include a component consisting of reduced generation from
affected EGUs,
[[Page 34884]]
with the measures in building block 3 serving as a basis for
quantifying the amount of reduced generation and consequent
CO2 emission reductions. Because of the availability of
those measures, the amount of reduced generation can be achieved while
continuing to meet the demand for electricity services in a reliable
and affordable manner. This alternative BSER is discussed in Section
VI.E.7 below.
d. Building Block 4--Increased Demand-Side Energy Efficiency
Building block 4--reducing CO2 emissions at and reducing
generation from affected EGUs by promoting demand-side energy
efficiency that reduces the amount of generation required from affected
EGUs--is a component of the BSER because the demand-side energy
efficiency is technically feasible and of reasonable cost, and meets
the other requirements for a component of the ``best system of emission
reduction . . . adequately demonstrated.''
The EPA's analysis and conclusions regarding the technical
feasibility, costs, and magnitude of building block 4 are discussed in
Section VI.C.4 above. We consider demand-side energy efficiency
programs to be proven, well-established practices within the industry
that are consistent with industry trends. Greater demand-side energy
efficiency is already a common policy goal among states, and most
states already authorize or require implementation of demand-side
energy efficiency programs. Fossil fuel-fired EGUs can reduce their
generation. Owners of affected EGUs as well as other parties can
contract for demand-side energy efficiency. As discussed above,
coordination of these decisions in the integrated electricity system
can occur through a variety of mechanisms, some centralized and some
not. For example, an allowance system or tradable emission rate system
would provide incentives that promote the measures in building block 4
in the same manner as discussed above for other building blocks.
Building block 4 is also very attractive under other BSER criteria.
Demand-side energy efficiency avoids the non-air health and
environmental effects of the fossil fuel-fired generation for which it
substitutes. Further, by reducing the overall amount of electricity
that needs to be transmitted between EGUs and customers, demand-side
energy efficiency tends to relieve stress on the grid, thereby
increasing system reliability. Creating incentives for additional
demand-side energy efficiency is also consistent with the goals of
encouraging technological innovation in energy efficiency and
encouraging deployment of current advanced technologies. For all these
reasons, the measures in building block 4 qualify as a component of the
``best system of emission reduction . . . adequately demonstrated.''
The EPA notes that the alternative BSER discussed later would
include a component consisting of reduced generation from affected
EGUs, with demand-side energy efficiency serving as a basis for
quantifying the amounts of generation reductions and consequent
CO2 emission reductions that can be achieved while
continuing to meet the demand for electricity services in a reliable
and affordable manner. This alternate interpretation of the BSER is
discussed in Section VI.E.7 below.
5. Evaluation of Building Block Combinations Against the BSER Criteria
a. Combination of Building Blocks 1 and 2
The EPA has considered whether a combination of building blocks 1
and 2 would be the BSER. As described in Section VI.D above, we believe
that such a combination is technically feasible and would be a ``system
of emission reduction'' capable of achieving meaningful reductions in
CO2 emissions from affected EGUs at a reasonable cost. The
combination would also satisfy other BSER criteria. Nevertheless, we do
not propose that this combination should be the BSER because the
proposed combination of all four building blocks is capable of
achieving greater reductions in CO2 emissions from affected
EGUs at a lower cost.
The EPA believes that both building blocks 1 and 2 individually
satisfy the BSER criteria identified by the statute and the D.C.
Circuit, with one possible concern, related to a ``rebound effect,''
noted earlier. That concern is the potential for the heat rate
improvements in building block 1, if implemented in isolation, to make
coal-fired steam EGUs more competitive compared to other EGUs and cause
them to increase their generation, creating a ``rebound effect'' that
would make building block 1 less effective at reducing CO2
emissions. As discussed above, building blocks 1 and 2 each appear
attractive or neutral with respect to each of the other BSER criteria.
With respect to most of the BSER criteria, there is no reason to
expect that the combination of building blocks 1 and 2 would be
evaluated differently from the individual building blocks. However, as
noted earlier, the combination addresses the concern about building
block 1 regarding a potential rebound effect, and in that important
respect it performs better than building block 1 considered in
isolation. The substitution of NGCC generation for generation from
coal-fired and other steam EGUs ensures that generation from coal-fired
EGUs, as a group, would not increase as a result of their improved
variable costs, with the result that the reduction in CO2
emission rates of coal-fired EGUs brought about by heat rate
improvements would not be offset by an increase in CO2
emissions due to increased generation from those EGUs. The combination
of building blocks would therefore be capable of achieving greater
reductions in CO2 emissions from affected sources than
either building block in isolation.
While achieving substantially greater emission reductions than
building block 1 alone, by reducing overall generation from coal-fired
EGUs the combination of building blocks 1 and 2 also has the potential
to raise the cost of the portion of the overall emission reductions
achievable through heat rate improvements relative to the cost of those
reductions if building block 1 were implemented in isolation.\218\
However, the EPA believes that the cost of emission reductions achieved
through heat rate improvements would remain reasonable for two reasons.
First, as discussed in Section VI.C.1 above, the cost of CO2
emission reductions achievable through heat rate improvements is quite
low, and that cost would remain reasonable even if it was substantially
increased. Second, although under the combination of building blocks 1
and 2 the volume of coal-fired generation would decrease, that decrease
is unlikely to be spread uniformly among all coal-fired EGUs. It is
more likely that some coal-fired EGUs would decrease their generation
slightly while others would decrease their generation by larger
percentages or cease operations altogether. We would expect EGU owners
to take these changes in EGU operating patterns into account when
considering where to invest in heat rate improvements, with the result
that there would be a tendency for such investments to be concentrated
in EGUs whose generation output was expected to decrease the
[[Page 34885]]
least. This enlightened bias in spending on heat rate improvements--
that is, focusing investments on EGUs where such improvements would
have the largest impacts and produce the highest returns, given
consideration of projected changes in dispatch patterns--would tend to
mitigate any deterioration in the cost of CO2 emission
reductions achievable through heat rate improvements.
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\218\ If an EGU produces less generation output, then an
improvement in that EGU's heat rate and rate of CO2
emissions per unit of generation produces a smaller reduction in
CO2 emissions. If the investment required to achieve the
improvement in heat rate and emission rate is the same regardless of
the EGU's generation output, then the cost per unit of
CO2 emission reduction will be higher when the EGU's
generation output is lower.
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As noted above, the EPA invites comment on a potential BSER
comprising building blocks 1 and 2, in light of the considerations that
could support this approach.
b. Combination of All Four Building Blocks
The EPA's proposed BSER is a combination of all four building
blocks. For the reasons described below, and similar to each of the
building blocks, the combination must be considered a ``system of
emission reduction.'' Moreover, as also discussed below, the
combination qualifies as the ``best'' system that is ``adequately
demonstrated.'' The combination is technically feasible; it is capable
of achieving meaningful reductions in CO2 emissions from
affected EGUs at a reasonable cost; it satisfies the other BSER
criteria as well; and its components are well-established. The
combination of all four building blocks would achieve greater
CO2 emission reductions at a lower cost than the combination
of building blocks 1 and 2 described above, and would also perform
better against other BSER criteria. We therefore propose to find the
combination of all four building blocks to be the ``best system of
emission reduction . . . adequately demonstrated'' for reducing CO
emissions at affected EGUs.\219\
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\219\ The analysis of the interactions among building blocks
provided above for the combination of building blocks 1 and 2,
indicating that the addition of building block 2 would mitigate the
potential concern about a ``rebound effect'' if building block 1
were implemented in isolation, applies to the combination of all
four building blocks as well; in fact, the addition of building
blocks 3 and 4 would further mitigate that concern. The EPA believes
that if implemented in combination, each of the four building blocks
would achieve substantial reductions in CO2 emissions
from affected EGUs at a reasonable cost.
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The assessments of the individual building blocks against the BSER
criteria would generally apply in the same way to those building blocks
when implemented as the combination of all four building blocks, with
the same exceptions as discussed above with respect to the combination
of building blocks 1 and 2 as well. However, the combination of all
four building blocks would improve upon the combination of building
blocks 1 and 2 in several respects. First, because of the potential of
building blocks 3 and 4 to achieve additional CO2 reductions
at reasonable costs, the broader combination would achieve greater
CO2 emission reductions at a lower average cost. Second, by
encompassing the increased low-and zero-carbon generation in building
block 3, the broader combination would reduce reliance on fossil fuels
and improve fuel diversity. Third, by encompassing the increased
demand-side energy efficiency in building block 4, the broader
combination would reduce the amount of electricity that would need to
be delivered over the electric grid, generally reducing pressure on the
grid and thereby improving electricity system reliability. These
considerations all support basing the BSER on the combination of all
four building blocks. They also support basing the BSER, in the
alternative, on the combination of building block 1 and reduced
generation in the amounts facilitated by the remaining building blocks.
As has been discussed in earlier portions of the preamble, the
costs and energy impacts of each of the four building blocks
individually are reasonable when viewed either at the individual source
level or through the lens of the electricity system as a whole, a
conclusion that holds for the combination of the building blocks as
well. Moreover, the flexibility available to states and regulated
entities to rely more extensively in their plans and strategies on
whichever measures best suit their particular circumstances will
further improve cost effectiveness. The analysis the EPA performed to
assess the costs, benefits, and other impacts of the proposed goals
reflects this compliance flexibility, along with transmission and
pipeline capabilities and constraints, fuel market and electricity
dispatch dynamics, and seasonal electricity load requirements. As
described below in Section X, the results indicate that the proposed
state goals (discussed in Section VII) are readily achievable with no
adverse impacts on electricity system reliability, and that impacts on
retail electricity prices are modest and fall within the range of price
variability seen historically in response to changes in factors such as
weather and fuel supply. Further, the costs tend to decline over time
as states and regulated entities take advantage of the available
flexibility and expand deployment of more cost-effective measures
(notably demand-side energy efficiency). The EPA considers this
analysis strong confirmation of the reasonableness of the costs of the
measures in the four building blocks in combination as the best system
of emission reduction.
6. Additional Considerations Related to Inclusion of Building Blocks 2,
3, and 4 as Part of the Basis Supporting the BSER
In this section, we discuss additional reasons why the measures in
building blocks 2, 3, and 4, individually and in combination, meet the
requirements to be components of the BSER. In particular, we discuss
why they meet the definition of a ``system of emission reduction,'' and
we provide additional reasons why they are the ``best'' that is
``adequately demonstrated.'' The interconnected nature of the electric
system is an important part of our reasoning.
a. ``System of Emission Reduction''
For the convenience of the reader, it is useful to reiterate the
key CAA section 111 requirements: Section 111(d)(1) requires that each
state's plan ``establish[] standards of performance for any existing
source'' for certain types of air pollutants; and section 111(a)(1)
defines a ``standard of performance'' as ``a standard for emissions . .
. which reflects the degree of emission limitation achievable through
the application of the best system of emission reduction . . .
adequately demonstrated.'' These provisions require that, in this
rulemaking, the affected sources must be subject to emissions
standards, but the basis for those standards--the ``system of emission
reduction''--may be any method that reduces the affected sources'
emissions, as long as that method is a ``system'' that meets the
criteria for being the ``best'' that is ``adequately demonstrated.''
As discussed in the Legal Memorandum, the EPA is justified in
adopting this interpretation under the first step of the framework for
administrative agencies to construe statutes that the U.S. Supreme
Court established in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-844
(1984) (Chevron), which we refer to as Chevron step 1.
Specifically, the term ``system,'' which is not defined in the CAA,
is broad: ``A set of things working together as parts of a mechanism or
interconnecting network.'' \220\ The
[[Page 34886]]
remaining provisions of the definition of ``standard of performance''
do not include any constraints on the ``set of things'' that may
constitute a ``system of emission reduction.'' Nor does the context in
which ``standard of performance'' is found--the provisions of section
111(d)(1)--add constraints on the things that may constitute such a
system. Rather, it is clear from these CAA provisions that anything
that reduces the emissions of affected sources may be considered a
``system of emission reduction'' for those sources. For this reason,
the measures in building blocks 2, 3, and 4 must be considered
components of such a system.
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\220\ Oxford Dictionary of English (3rd ed.) (published 2010,
online version 2013), http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/9780199571123.001.0001/acref-9780199571123.
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Even if these CAA provisions leave room for interpretation as to
whether those measures must be considered components of such a system,
the EPA's interpretation that they do is reasonable. As discussed in
the Legal Memorandum, the EPA is justified in adopting this
interpretation under the second step of the Chevron framework, which we
refer to as Chevron step 2. There are several reasons. In enacting the
CAA, Congress established ``pollution prevention'' as a ``primary
goal'' of the Act, and described it as ``the reduction or elimination,
through any measures, of the amount of pollutants produced or created
at the source.'' \221\ Building blocks 2, 3, and 4 are pollution
prevention measures, and, in light of the importance of pollution
prevention in the CAA, it is reasonable to interpret ``system of
emission reduction'' in section 111 to incorporate those measures. In
addition, the breadth of ``system of emission reduction'' is confirmed
by contrasting it with other provisions in the CAA that prescribe
specific types of controls as the basis for emission limits.\222\
Further support is found in Title IV of the CAA, in which Congress
established the program that regulates fossil fuel-fired power plants
to reduce their emissions of SO2 and NOX, the
precursors to acid deposition. In designing Title IV, Congress
recognized the integrated nature of the electricity sector and how that
integration could be harnessed to reduce air pollutant emissions. In
fact, Congress included provisions to encourage re-dispatch to lower-
emitting sources, renewable energy, and demand-side energy efficiency,
all of which are measures in those building blocks.\223\ All this
supports the reasonableness of interpreting ``system of emission
reduction'' in CAA section 111 to incorporate those measures. It should
also be noted that a number of commentators in the private sector and
academia have indicated support for interpreting the term, ``system of
emission reduction'' to base the CAA section 111(d) standards of
performance on measures such as re-dispatch, renewable energy, and
demand-side energy efficiency.\224\ Some stakeholders have as
well.\225\
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\221\ CAA Sec. 101(a)(3), (c).
\222\ For example, as discussed in the Legal Memorandum, CAA
Sec. 407(b)(2) requires the EPA to base the nitrogen oxides
(NOX) emission limits for certain types of boilers ``on
the degree of reduction achievable through the retrofit application
of the best system of continuous emission reduction . . . ;'' and
further requires the EPA to revise previously promulgated emission
limits for certain types of boilers ``to be more stringent if the
[EPA] determines that more effective low NOX burner
technology is available.'' (Emphasis added.)
\223\ CAA Sec. 401(b), 404(f)-(g).
\224\ See Nordhaus R., Gutherz I., ``Regulation of
CO2 Emissions from Existing Power Plants Under Sec.
111(d) of the Clean Air Act: Program Design and Statutory
Authority,'' Environmental Law Reporter, 44: 10366, 10384 (May 2014)
(``strong arguments for'' interpreting ``system'' to include
measures such as the addition of new zero-carbon generating capacity
and increases in end-user energy efficiency); Sussman R., ``Power
Plant Regulation Under the Clean Air Act: A Breakthrough Moment for
U.S. Climate Policy?'' Virginia Environment Law Journal, 32:97, 119
(2014) (``EPA would seem to have discretion to define `system' to
include any mix of strategies effective in reducing emissions.'');
Konschnik K., Peskoe A., ``Efficiency Rules: The Case for End-Use
Energy Efficiency Programs in the Section 111(d) Rule for Existing
Power Plants,'' Harvard Law School Environmental Law Program--Policy
Initiative 4 (March 3, 2014) (EPA is authorized to ``consider[ ] . .
. the entire [electricity grid] system when setting performance
standards.''); Monast J., Profeta T., Pearson B., Doyle J.,
``Regulating Greenhouse Gas Emissions From Existing Sources: Section
111(d) and State Equivalency,'' Environmental Law Reporter, 42:
10206, 10209 (March 2012) (``Demand-side energy-efficiency programs
and renewable energy generation may fit within the Sec. 111
framework, however, because both reduce the utilization of power
plant. . . . According to this reasoning, emission reductions are
occurring within the source category, because of changes in
generation at the power plant.'').
\225\ Ceronsky M., Carbonell T., ``Section 111(d) of the Clean
Air Act: The Legal Foundation for Strong, Flexible & Cost-Effective
Carbon Pollution Standards for Existing Power Plants,''
Environmental Defense Fund, at 9 (Oct. 2013), available at http://www.edf.org/sites/default/files/111-clean_air_act-strong_flexible_cost-effective_carbon_pollution_standards_for_existing_power_plants.pdf; Doniger D., ``Questions and Answers on
the EPA's Legal Authority to Set `System Based' Carbon Pollution
Standards for Existing Power Plants under Clean Air Act Section
111(d),'' NRDC [Natural Resources Defense Council] Issue Brief (Oct.
2013); ``Comments of the Attorneys General of New York, California,
Massachusetts, Connecticut, Delaware, Maine, Maryland, New Mexico,
Oregon, Rhode Island, Vermont, Washington, and the District of
Columbia on the Design of a Program to Reduce Carbon Pollution from
Existing Power Plants'' (Dec. 16, 2013).
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b. ``Best'' System That Is ``Adequately Demonstrated
As described earlier with respect to the individual building
blocks, the measures in each of building blocks 2, 3, and 4 meet the
criteria for the ``best'' system of emission reduction, and, generally
for the same reasons, the three in combination do as well.
In addition, the measures in building blocks 2, 3, and 4,
individually and in combination, are ``adequately demonstrated.'' As
discussed earlier, thanks to the integrated nature of the electricity
system, they have long been relied on to reduce costs in general,
assure reliability, and implement pre-existing pollution control
requirements in the least-cost manner. As also noted elsewhere in the
preamble, and discussed in more detail in the following subsections,
some utilities, states and regions are already relying on these
measures for the specific purpose of reducing CO2 emissions
from EGUs.
(i) Actions by Affected EGUs
Measures in building blocks 2, 3, and 4 may be undertaken or
invested in by the affected EGUs themselves, which supports that these
measures are ``adequately demonstrated.'' More specifically, the EPA
believes that owners of units operating across a wide range of
corporate, institutional and market structures (e.g., vertically
integrated utilities in regulated markets, independent power producers,
municipal utilities, and rural cooperatives) can take advantage of a
broad range of reduction opportunities included in the building blocks.
Because of the proposed lengthy planning period, owners can consider
longer-term options such as implementing energy efficiency programs or
replacement of older generating resources with more modern types of
generation, as well as shorter-term options such as heat rate
improvements and re-dispatch. Many companies, for example, already
factor a carbon cost adder into their long-term planning decisions.
Large vertically integrated utilities generally have options within
all four building blocks. They tend to have large and, as a general
matter, at least somewhat diverse generation fleets. For their higher-
emitting units, they have opportunities to use measures that reduce the
units' CO2 emission rates, such as heat rate improvements,
co-firing, or fuel switching. While this proposal preserves fuel
diversity, with over 30 percent of projected 2030 generation coming
from coal and over 30 percent from natural gas, even companies that
have traditionally depended upon coal to supply the majority of their
generation are diversifying their fleets, increasing their
[[Page 34887]]
opportunities for re-dispatch.\226\ Within the 5-to-15-year planning
horizon established in this proposal to begin in June 2015, most of
these companies are likely to be investing in new generation and can
consider options such as increased reliance on new renewable generating
capacity. They also run energy efficiency programs for their customers.
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\226\ http://online.wsj.com/article/PR-;CO-20140508-
;915605.html.
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Municipal utilities and rural cooperatives that own generating
asset portfolios also have multiple options for reducing CO2
emissions, particularly generation and transmission cooperatives and
larger municipal utilities. They can implement unit-specific
improvements, re-dispatch to lower emitting resources, employ energy
efficiency and renewable energy strategies, and explore longer-term
capacity planning strategies. For cooperatives and municipal utilities
with smaller fleets, re-dispatching among their own units may not
provide as many opportunities, particularly in the short term. But
because of the timing flexibility in the guidelines, these owners can
use both short-term dispatch strategies and longer-term capacity
planning strategies to reduce GHG emissions, and in many cases
financing is available at tax-advantaged or subsidized rates. At the
same time, in formulating their plans, states will be in a position to
recognize the distinctive attributes of smaller utilities--and, of
course, may consider participating in integrated multi-state compliance
strategies to increase the flexibility and cost-saving opportunities
that would be available to the covered EGUs.
Some stakeholders have expressed concerns that municipal utilities
and rural cooperatives can face other challenges as well. According to
these stakeholders, in deregulated areas, even though these utilities
may be fully vertically integrated entities, they may not have as much
flexibility to control dispatch because they are operating in a
competitive market, where they can be in a position in which they need
to operate if called upon. Even in this case, the timing flexibility of
the rule allows them to consider longer-term capacity planning
strategies. These can include building or contracting for electric
supply from lower-emitting sources, use of distributed renewable
technologies, and use of demand-side energy efficiency measures. There
are a number of municipal utilities and rural cooperatives that are
already aggressively pursuing such strategies.\227\ Nevertheless, in
recognition of stakeholders' expressed concerns, we invite comment on
whether there are special considerations affecting small rural
cooperative or municipal utilities that might merit adjustments to this
proposal, and if so, possible adjustments that should be considered.
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\227\ For examples, see Large Public Power Council, Energy
Efficiency Working Group, Second Annual Energy Efficiency
Benchmarking Report (2013); https://www.nreca.coop/nreca-on-the-issues/energy-operations/energy-efficiency/.
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Independent power producers (IPPs) may also face unique challenges
but nevertheless have options. Companies with coal-fired EGUs can
implement efficiency improvements as well as other unit-level
compliance options such as co-firing or fuel switching. While these
types of companies do not use the integrated resource planning process
that many vertically integrated utilities use, they still undertake
long-term business planning and as a result are in a position to
consider different long-term strategies related to their generating
assets. Many IPPs are actively developing renewable generating capacity
and natural gas-fired generating capacity. IPP owners could also fund
demand-side energy efficiency programs and document the resulting
electricity savings.
(ii) Actions by States
Another reason why the measures in building blocks 2, 3, and 4 are
``adequately demonstrated'' is that states may adopt them and, in fact,
many states have already adopted many of them.
For example, several states have already adopted renewable energy
(RE) and demand-side energy efficiency (EE) measures in their CAA
section 110 state implementation plans (SIPs) for attaining and
maintaining the national ambient air quality standards (NAAQS). The EPA
has provided initial guidance for states to do so.\228\ Some state air
agencies did so for their 1997 8-hour ozone NAAQS SIPs that were due in
2007; for example, Washington, DC, included the purchase of wind power
and the installation of LED traffic lights \229\; Dallas, Texas
included efficiency measures from the Texas Emissions Reduction Program
(TERP) \230\; and Connecticut included projects such as high efficiency
air conditioners, compact fluorescent lighting, combined heat and power
(CHP), and solar photovoltaic installations.\231\ Since that time, many
states have adopted legislative mandates for energy efficiency or
renewable energy, and states have expressed interest in including EE/RE
policies and programs in upcoming NAAQS SIPs. The EPA has provided
additional guidance \232\ and has partnered with the Northeast States
for Coordinated Air Use Management (NESCAUM) and three states
(Maryland, Massachusetts, and New York) to identify opportunities for
including EE/RE in a NAAQS SIP and to provide real-world examples and
lessons learned through those states' case studies.\233\
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\228\ See, e.g., Guidance on SIP Credits for Emission Reductions
from Electric-Sector Energy Efficiency and Renewable Energy Measures
(Aug. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; Incorporating Emerging and Voluntary Measures in a State
Implementation Plan (SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf.
\229\ DC Region 8-hour ozone SIP at 126, http://www.mwcog.org/uploads/pub-documents/9FhcXg20070525084306.pdf.
\230\ Dallas/Ft. Worth, Texas 8-hour ozone SIP, http://www.gpo.gov/fdsys/pkg/FR-2008-08-15/pdf/E8-18835.pdf.
\231\ CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1619 (see Attainment
Demonstration TSD, Chapter 8 at 31, http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_reports/section_8.pdf).
\232\ Roadmap for Incorporating EE/RE Policies and Programs into
SIPs/TIPs (July 2012), http://epa.gov/airquality/eere/manual.html.
\233\ States' Perspectives on EPA's Roadmap to Incorporate
Energy Efficiency/Renewable Energy in NAAQS State Implementation
Plans: Three Case Studies, Final Report to the U.S. Environmental
Protection Agency (Dec. 2013), http://www.nescaum.org/documents/nescaum-final-rept-to-epa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf.
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It should be recognized that each state's electric utility sector
operates under distinctive conditions and circumstances. The EPA's
proposal ensures that states retain flexibility to craft standards of
performance that can accommodate characteristics including fuel
sources, types of EGU owners within a state (e.g., investor-owned,
municipal, and cooperative utilities, and independent power producers),
and regulatory structure (e.g., regulated or restructured). States can
tailor their regulatory mechanisms to recognize differences, for
example by creating budgets on a company-wide basis or using market-
based mechanisms such as mass-based trading systems, to ensure that
requirements are achievable.
The proposal also recognizes that states have different resource
bases and energy policies in place, and these differences are taken
into account in the state goal-setting and computation process. For
instance, while the EPA's BSER assumptions consider re-dispatch to NGCC
units, they do not consider re-dispatch beyond the NGCC capacity
already existing in a state. In that way, the proposal does not presume
that
[[Page 34888]]
states with limited natural gas generation or infrastructure will have
to develop those resources.
Furthermore, while the BSER reflects best practices for both
renewables and energy efficiency, it also recognizes that some states
have made more progress than others in these areas. The BSER allows
time for states to ramp up to greater levels of energy efficiency and
use and development of renewable energy resources, should they choose
those approaches. With respect to renewable energy, the proposal also
recognizes that different areas of the country have different resource
bases and does not presume that a uniform level of penetration of
renewable generation is appropriate for every state.
The features provided in this proposal to ensure policy flexibility
can be used by all states to address their unique circumstances. In a
regulated state, if a company's compliance strategies included reducing
generation at higher-emitting EGUs, it would work through its state's
integrated planning process to ensure that adequate generation was
available through a combination of all four building blocks. Cost
recovery, and cost oversight, can be achieved through rate cases before
state regulators. In a restructured state, even if affected companies
responded to the guidelines by reducing generation without themselves
replacing that generation, the electricity markets that have developed
would react to ensure the availability of replacement generation. Other
companies would see opportunities to build or ramp up existing lower-
emitting generation, and in some markets that treat demand-side
resources on par with supply side resources, energy service companies
would likely see opportunities. Further, state regulators can continue
to play an important role in restructured states as well, authorizing
or reviewing both renewable energy procurement and demand-side energy
efficiency programs. In all types of market structures, large energy
users might independently see additional energy efficiency
opportunities or opportunities for self-generation using options such
as combined heat and power, solar, or power purchase agreements, and
states can structure their plans to allow the CO2 reductions
achieved at affected EGUs through such actions to assist in reaching
compliance. As discussed in earlier portions of this section and
elsewhere in the preamble, each of the building blocks is already being
widely implemented, is consistent with industry trends, and consists of
CO2 reduction methods already widely accepted in the eyes of
various stakeholders, as was clear from views expressed in our outreach
process.
Moreover, there are mechanisms through which states could require
measures from any of the building blocks in state plans. In fact, the
state plan formulation process through which CAA section 111(d) is
implemented reinforces the determination that these measures are
components of the BSER. For example, states would have authority to
impose measures such as best practices for operation and maintenance of
EGUs, dispatch limits, renewable energy resource requirements, and
demand-side energy efficiency requirements. States also would have
authority to establish requirements that change the relative costs of
generation from more carbon-intensive and less carbon-intensive EGUs,
for example by creating emission allowance systems that cause market
participants and system operators to take account of CO2
emission rates as an element of variable operating costs. Such an
approach can encourage measures from all of the building blocks
simultaneously. As noted elsewhere in the preamble, many states have
already pursued one or more of these approaches.\234\
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\234\ See the discussions of California California Global
Warming Solutions Act and RGGI above in this section and elsewhere
in the preamble.
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It also should be noted that during the public outreach sessions,
stakeholders generally recommended that state plans be authorized to
rely on, and that affected sources be authorized to implement, re-
dispatch, renewable energy measures, and demand-side energy efficiency
measures in order to meet states' and sources' emission reduction
obligations. The EPA agrees that state plans may include these
measures, at least under certain circumstances, as discussed in Section
VIII, and that sources may rely on them to achieve required reductions.
It is clear that these types of measures are well-accepted by the
stakeholders as means to reduce emissions from affected sources. The
fact that state plans and sources would be expected to use these types
of measures to reduce emissions supports the view that these measures
are part of a ``system of emission reduction'' for those sources that
the EPA may evaluate against the appropriate criteria to determine
whether they comprise the ``best system of emission reduction . . .
adequately demonstrated.''
(iii) Regional Organizations
Another reason why the measures in building blocks 2, 3, and 4 are
``adequately demonstrated'' is that they can be accommodated through
the existing regional components of the electricity system.
On the regional level, ISO/RTOs control dispatch and are
responsible for reliable operation of the bulk power system.\235\ They
can seek solutions, such as capacity markets and transmission upgrades,
to preserve resource adequacy and ensure the continued reliable
operation of the grid. For this proposal, the ISO/RTO Council has
already submitted a set of recommendations they believe can help
balance the needs of lower emissions, economic dispatch, and
reliability, which is discussed in greater detail in Section VIII.F.7
of this proposal.\236\ For areas of the country that are not covered by
an ISO/RTO, there are regional groups, such as ColumbiaGrid, Northern
Tier Transmission Group and WestConnect in the west, and system
operators such as Southern Company in the southeast, that can provide
these functions. In shifting to lower-emitting units, grid operators
across the country factor environmental costs into their economic
dispatch through a variety of mechanisms, including allowance costs,
variable costs associated with operating environmental controls, and
operating limits for high-emitting units.
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\235\ Across all markets, at the federal level, FERC and NERC
create and oversee standards for reliability. NERC works with
electric reliability councils and control areas that comprise all
types of utilities and system operators to ensure that adequate
generation is available.
\236\ http://www.isorto.org/Documents/Report/20140128_IRCProposal-ReliabilitySafetyValve-RegionalComplianceMeasurement_EPA-C02Rule.pdf.
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(iv) Concerns From Stakeholders; Solicitation of Comment
We note that some stakeholders have argued that CAA section
111(a)(1) does not authorize the EPA to identify re-dispatch, low- or
zero-emitting generation, or demand-side energy efficiency measures
(building blocks 2, 3, and 4) as components of the ``best system of
emission reduction . . . adequately demonstrated.'' According to these
stakeholders, as a legal matter, the BSER is limited to measures that
may be undertaken at the affected units, and not measures that are
beyond the affected units; the measures in building blocks 2, 3, and 4
are ``beyond-the-unit'' or ``beyond-the-fenceline'' measures because
they are implemented outside of the affected units and outside their
control; and as a result, those measures cannot be considered
components of the BSER.
We welcome comment on this issue. As discussed above, we propose
that the
[[Page 34889]]
provisions of CAA section 111 do not by their terms preclude the BSER
from including those types of measures. In addition, as noted above,
under our proposed approach, affected sources may themselves implement
the measures included in building blocks 2, 3, and 4, so that those
measures are within their control with the result of their application
being emissions reductions at affected EGUs. Moreover, under our
alternative approach, the ``system of emission reduction'' includes
reductions in utilization at the affected sources themselves.\237\ It
should also be noted that, as discussed above, the re-dispatch measures
in building block 2 are limited to affected sources. Thus, the proposed
approach and alternative described above respond to these stakeholder
concerns.
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\237\ Commenters have critiqued this ``at-the-unit'' and
``beyond-the-unit'' distinction as follows:
There is an argument that the at-the-unit/beyond-the-unit
distinction is not a meaningful one. Specifically, it could be
argued that the distinction between at-the-unit and beyond-the-unit
measures is largely artificial, because all of the emission
reductions under consideration--whether from at-the-unit measures
(e.g., fuel-switching or efficiency upgrades) or from beyond-the-
unit measures--are, in fact, emission reductions at or from electric
generating units on the interconnected electric grid. For example,
neither the addition of renewable generation nor the reduction of
end-user demand directly reduces atmospheric emission of
CO2; rather these measures permit fossil EGUs to reduce
their own output and emissions. It can be argued that all of the
systems of emission reduction here contemplated--whether they
involve end-use energy efficiency, displacing high-emission
generation with lower emission generation, fuel-switching, heat-rate
improvements, etc.--are effectively at-the-unit measures that
ultimately reduce emissions solely from regulated EGUs. If energy-
efficiency programs, added renewable energy, and redispatch from
higher emitting facilities to lower emitting facilities are viewed
as at-the-unit systems of emission reduction, the at-the-unit/
beyond-the-unit distinction arguably becomes irrelevant--at least
from a legal perspective. Rather, the real issue may come down to
whether Sec. 111(d) authorizes the EPA to require EGUs to curtail
their output of electricity as a means of complying with the rule.
Nordhaus R., Gutherz I., ``Regulation of CO2
Emissions from Existing Power Plants Under Sec. 111(d) of the Clean
Air Act: Program Design and Statutory Authority,'' Environmental Law
Reporter, 44: 10366, 10383 n. 133 (May 2014).
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7. Alternate Approach to the Best System of Emission Reduction
As an alternative to the approach described above for determining
the ``best system of emission reduction . . . adequately
demonstrated,'' the ``system of emission reduction'' may be identified
as including, in addition to building block 1, the reduction of
affected fossil fuel-fired EGUs' mass emissions achievable through
reductions in generation of specified amounts from those EGUs. Under
this approach, the measures in building blocks 2, 3, and 4 would not be
components of the system of emission reduction but instead would serve
as bases for quantifying the reduced generation (and therefore
emissions) at affected EGUs, and assuring that the amount of reduced
generation meets the criteria for the ``best'' system that is
``adequately demonstrated'' because, among other things, the reduced
generation can be achieved while the demand for electricity services
can continue to be met in a reliable and affordable manner.
Specifically, the amount of generation from the increased utilization
of NGCC units would determine a portion of the amount of the generation
reduction component of the BSER for affected fossil fuel-fired steam
EGUs, and the amount of generation from the use of expanded low- and
zero-carbon generating capacity that could be provided, along with the
amount of generation from fossil fuel-fired EGUs that could be avoided
through the promotion of demand-side energy efficiency, would determine
a portion of the amount of the generation reduction component of the
BSER for all affected EGUs.
Reduced generation is encompassed by the terms of the phrase
``system of emission reduction'' in CAA section 111(a)(1), as a matter
of Chevron step 1, because, in accordance with the above-discussed
definition of ``system,'' reduced generation is a ``set of things''--
which include reduced use of generating equipment and therefore reduced
fuel input--that the affected source may take to reduce its
CO2 emissions.\238\ If that phrase is not considered clear
by its terms, then, under Chevron step 2, it may reasonably be
interpreted to include reduced generation.\239\ As discussed in the
Legal Memorandum, the legislative history of the 1970 CAA Amendments
indicates that Congress recognized that emitting sources could comply
with pollution control requirements by reducing production, including
retiring.\240\ As also noted in the Legal Memorandum, examples of
reduced utilization as a means of reducing emissions are found in
settlement agreements between the EPA and fossil fuel-fired EGUs to
resolve alleged violations of the CAA new source review (NSR)
requirements.\241\
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\238\ For this reason, under a Chevron step 1 interpretation,
``system of emission reduction'' includes reduced generation.
\239\ For these reasons, under a Chevron step 2 interpretation,
``system of emission reduction'' includes reduced generation.
\240\ See CAA section 110(g) (authorizing temporary emergency
suspensions of SIP revisions if needed to prevent the closing of a
source of air pollution), enacted as CAA section 110(f) in the 1970
CAA Amendments; 116 Cong. Rec. 42384 (Dec. 18, 1970), reprinted in
Congressional Research Service, A Legislative History of the Clean
Air Act Amendments of 1970, vol. 1, at 132-33 (1974) (statement of
Sen. Muskie) (discussing criteria for sources to receive compliance
date extensions). Sen. Muskie added that the emission standards set
by the EPA for hazardous air pollutants ``could include emission
standards which allowed for no measureable emissions,'' id., which
further suggests that, as a practical matter, the standards could
result in reduced production.
\241\ See, e.g., Consent Decree at 18, United States v. Wis.
Power & Light Co., No. 13-cv-266 (W.D. Wis. filed Apr. 22, 2013),
available at http://www2.epa.gov/sites/production/files/documents/wisconsinpower-cd.pdf.
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Reduction of, or limitation on, the amount of generation is already
a well-established means of reducing emissions of pollutants in the
electric sector, notwithstanding the fact that as a practical matter,
some facilities may have to operate, or remain available, to ensure
system reliability. For example, reduced generation by higher-emitting
sources is one of the compliance options available to, and used by,
EGUs to comply with the Clean Air Act acid rain program in CAA title
IV, as well as the transport rules that we refer to as the
NOX SIP Call \242\ and the Clean Air Interstate Rule
(CAIR).\243\ Reduction in generation is also a possible means by which
an EGU can achieve compliance with its requirements under RGGI.
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\242\ 63 FR 57356 (Oct. 27, 1998).
\243\ 70 FR 25162 (May 12, 2005).
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Reduced generation in specified amounts is part of the ``best''
system of emission reduction that is ``adequately demonstrated.''
Reduced generation is technically feasible because of a source's
ability to limit its own operations. In addition, the amounts of
generation and emission reductions may be determined with precision
through the application of building block 2, 3, and 4 measures for
increased generation from low- or zero-emitting sources and increased
demand-side energy efficiency, which, in turn, ensure the reliability
of the electricity grid and the affordability of electricity to
businesses and consumers.
Because of the availability of the measures in building blocks 2,
3, and 4, the proposed levels of reduced generation are of reasonable
cost for the affected source category and the nationwide electricity
system, do not jeopardize reliability, result in an important amount of
emission reductions, are consistent with current trends in the
electricity sector, and promote the development and implementation of
technology that is important for continued emissions reductions. All
these results come about because the operation of the electrical
[[Page 34890]]
grid through integrated generation, transmission, and distribution
networks creates fungibility for electricity and electricity services,
which allows decreases in generation at affected fossil fuel-fired
steam EGUs to be replaced by increases in generation at affected NGCC
units (building block 2) and allows decreases in generation at all
affected EGUs to be replaced by increased generation at low- or zero-
carbon EGUs (building block 3) or by decreased demand (building block
4). Further, this fungibility increases over longer timeframes with the
opportunity to invest in infrastructure improvements, and as noted
elsewhere, this proposal provides an extended state plan and source
compliance horizon. These characteristics of the integrated electricity
system assure that reduced generation in specified amounts meets the
criteria to qualify as part of the ``best'' system of emission
reduction.
Reduced generation in those amounts is also ``adequately
demonstrated.'' As noted above, the measures in building blocks 2, 3,
and 4 are already in widespread use in the industry. At the levels
proposed, they have the technical capability to substitute for reduced
generation at some or all affected EGUs at reasonable cost. The NGCC
capacity necessary to accomplish the levels of generation reduction
proposed for building block 2 is already in operation or under
construction. Moreover, it is reasonable to expect that the incremental
resources reflected in building blocks 3 and 4 will develop at the
levels requisite to ensure an adequate and reliable supply of
electricity at the same time that affected EGUs may choose or be
required to reduce their CO2 emissions by means of reducing
their utilization. There are several reasons for this. First, the
affected sources themselves could invest in new renewable energy
resources and demand-side energy efficiency, as discussed above.\244\
Second, the states, as part of their plans, have mechanisms available
to put these substitutes in place: They could establish requirements or
incentives that would result in new renewable energy and demand-side
energy efficiency programs, as also discussed above.\245\ Third, as
also discussed above, regional entities in the electricity system can
accommodate these substitutes.
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\244\ It should be noted that in light of the low current and
projected near term prices for natural gas, market forces may lead
investors to choose to build new NGCC units, rather than new
renewable resources. This result would not call into question the
technical feasibility of a BSER that included reductions in fossil
fuel-fired generation by the amount of a specified amount of new
renewable resources. This is because under these circumstances, the
fossil fuel-fired generators could still reduce their generation
without causing reliability or other problems in the electric power
system.
\245\ The nuclear generating capacity reflected in building
block 3 is already in operation or under construction.
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Most broadly, with respect to the measures in building blocks 2, 3,
and 4, provided there is sufficient lead time for planning, mechanisms
are in place in both regulated and deregulated electricity markets to
assure that substitute generation will become available and/or steps to
reduce demand will be taken to compensate for reduced generation by
affected EGUs. These mechanisms are based on, among other things, the
integrated nature of the electricity system coupled with the
availability of capacity in existing NGCC units, the growing
institutional capacity of entities that develop renewable energy and
demand-side energy efficiency resources, and the ability of system
operators and state regulators to incentivize further development of
those resources.
The EPA solicits comment on whether measures in addition to those
in building blocks 2, 3, and 4 could support the showing that reduced
utilization is ``adequately demonstrated,'' including additional NGCC
capacity that may be built in the future, as discussed in Section
VI.C.5.c above.
8. The EPA's Discretion in Applying the Criteria for the Best System of
Emission Reduction
As discussed above, each of the approaches to determining the
``best system of emission reduction . . . adequately demonstrated''
entails applying the criteria described in the D.C. Circuit case law
for evaluating the BSER. It should be emphasized that under the case
law, the EPA has significant discretion in weighing the different
criteria, and may weigh them differently in different rulemakings.
For the present proposal, the EPA is heavily weighting three
criteria in particular: The amount of emission reductions, the cost of
achieving those reductions, and the promotion of technology
implementation--while also noting that the proposed BSER determination
readily meets the other criteria as well. The EPA considers it
especially important in this rulemaking, while ensuring that
electricity system reliability is preserved and that costs are not
unreasonable, to achieve a significant amount of emissions reductions
in response to the urgency and the magnitude of the need to mitigate
climate change. The EPA discusses this above in the sections concerning
the scientific background for this rulemaking. The EPA also considers
it especially important for the present proposal that the overall costs
of achieving the emission reductions should be reasonable. Costs can be
minimized through the flexibility to choose from a broad range of
CO2 emission reduction measures, as is provided in the
portion of this proposal addressing state plans, and a similarly broad
range of emission reduction measures, represented by the four building
blocks discussed above, should serve as the basis supporting the BSER.
Finally, the EPA also considers it especially important for the present
proposal to promote technological innovation and development of, in
particular, the measures in building blocks 3 and 4 (to reiterate, low-
or zero-carbon electricity generation and demand-side energy
efficiency, respectively). Promoting innovation in, and market
penetration of, these technologies and practices is critical to making
the substantial reductions in emissions that will be required during
the next few decades to reduce the risks to public health and welfare
and our economic well-being of dangerous climate change.
In addition, in this rulemaking, the EPA is determining the BSER in
a manner that is consistent with, and that provides further impetus
for, current trends in the nation's electricity system that offer
promise to reduce the carbon intensity of the system over the near- and
long-term, while maintaining reliability and affordability. This
approach is consistent with the case law, which authorizes the EPA to
determine BSER by ``balanc[ing] long-term national and regional
impacts,'' and by ``using a long-term lens with a broad focus on future
costs, environmental and energy effects of different technological
systems. . . .'' \246\
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\246\ Sierra Club v. Costle, 657 F.2d 298, 331 (D.C. Cir. 1981).
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9. State-Wide Application of the BSER; Appropriateness of Standards of
Performance
An important aspect of the BSER for affected EGUs is that the EPA
is proposing to apply it on a statewide basis. The statewide approach
also underlies the required emission performance level, which is based
on the application of the BSER to a state's affected EGUs, and which
the suite of measures in the state plan, including the emission
standards for the affected
[[Page 34891]]
EGUs, must achieve overall. The state has flexibility in assigning the
emission performance obligations to its affected EGUs, in the form of
standards of performance--and, for the portfolio approach, in imposing
requirements on other entities--as long as, again, the required
emission performance level is met.
This state-wide approach both harnesses the efficiencies of
emission reduction opportunities in the interconnected electricity
system and is fully consistent with the principles of federalism that
underlie the Clean Air Act generally and CAA section 111(d)
particularly. That is, this provision achieves the emission performance
requirements through the vehicle of a state plan, and provides each
state significant flexibility to take local circumstances and state
policy goals into account in determining how to reduce emissions from
its affected sources, as long as the plan meets minimum federal
requirements.
In this subsection, we describe how this approach, and the
standards of performance for the affected EGUs that the states will
establish through the process we describe, are consistent with the CAA
section 111(d)(1) and (a)(1) provisions.
For convenience, we set out the requirements of CAA section
111(d)(1) and (a)(1) here: Under CAA section 111(d)(1), the state must
adopt a plan that ``establishes standards of performance for any
existing source.'' Under CAA section 111(a)(1), a ``standard of
performance'' is a ``standard for emissions . . . which reflects the
degree of emission limitation achievable through the application of the
best system of emission reduction . . . adequately demonstrated.'' The
EPA proposes to interpret these provisions as set forth in this sub-
section.
The first step is for the EPA to determine the ``best system of
emission reduction . . . adequately demonstrated.'' As discussed at
length elsewhere, the EPA is proposing two alternative BSER. The first
is the measures in building blocks 1 through 4 combined. This includes
operational improvements and equipment upgrades that the coal-fired
steam EGUs in the state may undertake to improve their heat rate by, on
average, six percent and increases in, or retention of, zero- or low-
emitting generation, as well as measures to reduce demand for
generation, all of which, taken together, displace, or avoid the need
for, generation from the affected EGUs. This BSER is a set of measures
that impacts affected EGUs as a group. The alternative approach to BSER
is building block 1 combined with reduced utilization from the affected
EGUs in the state as a group, in the amounts that can be replaced by an
increase in, or retention of, zero- or low-emitting generation, as well
as reduced demand for generation.
After determining the BSER, the EPA then applies the BSER to each
state's affected EGUs, on a state-wide basis. Building block 1 is
applied to the coal-fired steam EGUs on a statewide basis; building
block 2 is applied to increase the generation of the NGCC units in the
state up to certain amounts, and decrease the amount of generation from
steam EGUs accordingly; and the measures in building blocks 3 and 4 are
applied to reduce, or avoid, generation from all affected EGUs on a
state-wide basis. Under the alternative formulation of the BSER, the
total amount of reduced generation from the affected EGUs in the state,
associated with the measures in building blocks 2, 3, and 4, is
determined on the basis of each state's affected EGUs as a group.
This statewide approach to applying the BSER is consistent with the
CAA section 111(a)(1) definition of ``standard of performance,'' which,
as quoted above, refers to ``the application of the [BSER],'' for the
purpose of determining ``the degree of emission limitation
achievable,'' but does not otherwise constrain how the BSER is to be
applied.
As a result, the EPA may apply the BSER to all of the affected EGUs
in the state as a group. Similarly, the implementing regulations give
the EPA broad discretion to identify the group of sources to which the
BSER is applied. The regulations provide that the EPA ``will specify
different emission guidelines or compliance times or both for different
sizes, types, and classes of designated facilities when costs of
control, physical limitations, geographical location, or similar
factors make subcategorization appropriate.'' Applying the BSER to the
affected EGUs in each state as a group is appropriate, and therefore is
consistent with these regulations.
As part of applying the BSER, the EPA, to return to provisions of
CAA section 111(a)(1), calculates the ``emission limitation achievable
through the application of the [BSER].'' In this rulemaking, we refer
to this amount as the state goal. As noted, the EPA expresses the state
goal in the emission guidelines as an emission rate.
The state must develop a state plan that achieves the state goal,
either in the form of an emission rate, as specified for the state in
the emission guidelines, or a translated mass-based version of the
rate-based goal. We refer to the state goal, in the form used by the
state as the foundation of its plan, as the required emission
performance level.
As part of its state plan, the state must establish ``standards of
performance'' for its affected EGUs. To do so, the state may consider
the measures the EPA identified as part of the BSER or other measures
that reduce emissions from the affected EGUs. Moreover, the state has
the flexibility to establish emission standards in the degree of
stringency that the state considers appropriate. The primary limitation
on the state's flexibility is that the emission standards applied to
all of the state's affected EGUs--and, in the case of states that adopt
the portfolio approach, the requirements imposed on other affected
entities--taken as a whole, must be demonstrated to achieve the
required emission performance level. In addition, the state may make
the emission standards for any of its affected EGUs sufficiently
stringent, so that the standards and any requirements imposed on other
affected entities (if relevant), taken as a whole, achieve a level of
emission performance that is better than the required emission
performance level. See CAA section 116, 40 CFR 60.24(g).
Under these circumstances--that the emission standards that the
state establishes for its affected EGUs and any other requirements for
the other affected entities, as relevant, taken together, are at least
as stringent as necessary to achieve the required emission performance
level for the state's affected EGUs--each emission standard that the
state adopts for each of its affected EGUs will meet the definition of
a ``standard of performance'' under CAA section 111(a)(1).
Specifically, the ``standard of performance'' for each source will
constitute, to return to the provisions of CAA section 111(a)(1), ``a
standard for emissions which reflects [that is, embodies, or
represents] \247\ the degree [that is, the portion] of emission
limitation achievable through the application of the [BSER]'' [that is,
as noted above, the required emission performance level for all
affected sources in a state]. That ``degree'' or portion of the
required emission performance level is, in effect, the portion of the
state's obligation to limit its affected sources' emissions that the
state has assigned to each particular affected source. An emission
standard
[[Page 34892]]
meets this definition of the term ``standard of performance''
regardless of whether it is part of a plan that adopts the portfolio
approach (in which case, the standard will reflect a relatively smaller
part of the emission performance level) or one that imposes the plan's
emission limitation obligations entirely on the affected EGUs (in which
case, the standard will reflect a relatively larger part of the
emission performance level).
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\247\ See Oxford Dictionary of English (3rd ed. 2010 (online
version 2013)) (defining ``reflect'' as, among other things,
``embody or represent (something) in a faithful or appropriate
way'').
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These proposed interpretations of the provisions of CAA sections
111(d)(1) and (a)(1) are fully consistent with the EPA's overall
approach in this rulemaking to determining and applying the BSER and
identifying the appropriate level of emission performance for the
affected EGUs. As noted, this approach entails applying the BSER on a
state-wide basis and, based on the BSER, identifying the emission
performance level for each state's affected EGUs that each state must
achieve, so that each state may then assign the emission limitation
obligations among its sources. As noted, this approach is fully
consistent with the interconnected nature of the electricity system and
with the principles of federalism that underlie CAA section 111(d).
It should be emphasized that each state has many options for
assigning the emission limitation obligations among its affected
sources. For example, the state could impose emission standards that
are consistent with the BSER. Under these circumstances, the state may
assign to different affected sources emission standards with different
levels of stringency because the state will have determined that those
standards are consistent with the nature of each source's participation
in the state's electricity system. In addition, the state could
authorize emission trading as part of the emission standards for
affected sources. Under these circumstances, if an affected source's
emission level was higher than the standard the state established for
it, the source could achieve the standard by purchasing additional
emission rights through the trading program.
Finally, it should be noted that states retain authority under CAA
section 116 and 40 CFR 60.24(g) to impose standards of performance
that, cumulatively, are more stringent than the emission performance
level.\248\
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\248\ The EPA's approach may also be characterized as (i)
determining the BSER for the affected EGUs, (ii) establishing as the
emission guideline the standard for emissions that the affected EGUs
in the state can achieve on average through the application of the
BSER, and (iii) as part of the emission guideline, authorizing each
state to establish as the applicable standard for each affected EGU,
the standard that the state considers appropriate and that when
totaled with the standards established for the other EGUs (and as
may be adjusted to account for the portfolio approach, if that
approach is adopted by the state) is at least as stringent as the
average standard in the emission guideline. As noted in the
accompanying text, a state has many ways to establish standards that
meet the CAA requirements, including, for example, following the
BSER or authorizing emission rate averaging or trading.
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10. Combined Categories
As discussed above, the EPA is soliciting comment on combining the
category of steam EGUs and the category of combustion turbines (which
include NGCC units) into a single category for fossil fuel-fired EGUs,
for purposes of promulgating emission guidelines for CO2
emissions. The EPA solicits comment on whether combining the categories
is, as a legal matter, a prerequisite for (i) identifying as a
component of the BSER re-dispatch between sources in the two categories
(i.e., re-dispatch between steam EGUs and NGCC units), or (ii)
facilitating averaging or trading systems that include sources in both
categories, which states may wish to adopt.
11. Severability
We consider our proposed findings of the BSER with respect to the
various building blocks to be severable, such that in the event a court
were to invalidate our finding with respect to any particular building
block, we would find that the BSER consists of the remaining building
blocks. The state goals that would result from any combination of the
building blocks can be computed from data included in the Goal
Computation TSD and its appendices using the methodology described in
the preamble and that TSD.
12. Solicitation of Comment
We invite comment on all aspects of our proposed interpretation and
alternate interpretation of the BSER for CO2 emissions from
existing fossil fuel-fired EGUs, both as identified above and as
further discussed in the Legal Memorandum in the docket.\249\ In
particular, we invite comment on our analysis of the four building
blocks as components of the BSER, whether any other potential measures
should be considered, our analysis of the combinations of building
blocks 1 and 2 and of all four building blocks, and the legal,
technical, and economic bases of our conclusions. With regard to
comments received during the stakeholder meetings, some commenters
noted that trading programs like RGGI have been successful at reducing
GHGs, and other commenters provided specific BSER proposals based on
trading and/or emissions averaging approaches. We specifically request
comment on whether any of these approaches should be considered as the
BSER. We also specifically invite comment on the question, raised by
some stakeholders, as to whether if measures may be relied on in the
state plan to achieve emissions reductions, they cannot be excluded
from the scope of the BSER solely because they involve actions by
entities or at locations other than affected sources.
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\249\ However, as noted, we are not soliciting comment on issues
that were resolved by the implementing regulations.
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VII. State Goals
A. Overview
In this section, the EPA sets out proposed state-specific
CO2 emission performance goals to guide states in
development of their state plans. The proposed goals reflect the EPA's
quantification of each state's average emission rate from affected EGUs
that could be achieved by 2030 and sustained thereafter, with interim
goals that would apply over a 2020-2029 phase-in period, through
reasonable implementation, considering the unique circumstances of each
individual state, of the best system of emission reduction adequately
demonstrated (based on all four building blocks) described above. In
addition, we are taking comment on a second set of state-specific goals
that would reflect less stringent application of the same BSER, in this
case by 2025, with interim goals that would apply over a 2020-2024
phase-in period. As promulgated in the final rule following
consideration of comments received, the interim and final goals will be
binding emission guidelines for state plans.
The proposed goals are expressed in the form of state-specific,
adjusted \250\ output-weighted-average CO2 emission rates
for affected EGUs. However, states are authorized to translate the form
of the goal to a mass-based form, as long as the translated goal
achieves the same degree of emission limitation.\251\
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\250\ As described below, the emission rate goals include
adjustments to incorporate the potential effects of emission
reduction measures that address power sector CO2
emissions primarily by reducing the amount of electricity produced
at a state's affected EGUs (associated with, for example, increasing
the amount of new low- or zero-carbon generating capacity or
increasing demand-side energy efficiency) rather than by reducing
their CO2 emission rates per unit of energy output
produced.
\251\ A method for translating from a rate-based goal to a mass-
based goal is discussed in the Projecting CO2 Emission
Performance in State Plans TSD.
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The EPA is also proposing that measures taken by a state or its
sources
[[Page 34893]]
after the date of this proposal, or programs already in place, and
which result in CO2 emission reductions at affected EGUs
during the 2020-2030 period, would apply toward achievement of the
state's CO2 goal. Thus, states with currently existing
programs and policies, and states that put in place new programs and
policies early, will be better positioned to achieve the goals.
The EPA is proposing to finalize the goal for each state as
proposed, and adjusted as may be appropriate based on comments. A state
may demonstrate during the comment period that application of one of
the building blocks to that state would not be expected to produce the
level of emission reduction quantified by the EPA because
implementation of the building block at the levels envisioned by the
EPA was technically infeasible, or because the costs of doing so were
significantly higher than projected by the EPA. While the EPA would
consider this in setting final state goals, the EPA would also consider
(and would expect commenters to address) whether a similar overall
state goal could still be achieved through more aggressive
implementation of one or more of the measures encompassed in the other
building blocks or through other, comparable measures. For example, if
a state demonstrates during the public comment period that the state's
coal-fired steam EGUs could only achieve an average four percent heat
rate improvement, instead of the six percent that the EPA is proposing
to determine is achievable from application of building block 1, the
EPA would not adjust the state's goal to reflect that change unless the
state also demonstrates that it could not get additional reductions
from application of building blocks 2, 3 or 4, or in related,
comparable measures.
Each of the building blocks establishes a reasonable level of
reductions, but not necessarily the maximum amount that could be
achieved if that building block, and no other, were the basis
supporting the BSER. Together the building blocks establish a
reasonable overall level of reductions and effort that the EPA
considers appropriate at this time. This amount of emission reductions
is significant and will require effort and adjustments throughout the
electricity sector. In light of the overall effort to achieve the state
goals based on a combination of all four building blocks at the levels
specified, the EPA is not proposing a higher level of reductions at
this time, even though the measures in the building blocks could be
implemented more stringently to achieve greater emission reductions.
Because the building blocks each establish a reasonable level of
emission reduction rather than the maximum possible level of reduction,
the EPA expects that, for any particular state, even if the application
of the measures in one building block to that state would not produce
the level of emission reductions reflected in the EPA's quantification
for that state, the state will be able to reasonably implement measures
in other of the building blocks more stringently, so that the state
would still be able to achieve the proposed goal. Accordingly, the EPA
proposes that even if a state demonstrates during the comment period
that application of a building block to that state would not result in
the level of emission reductions reflected in the EPA's quantification
for that state, then the state should also explain why the application
of the other building blocks would not result in greater emission
reductions than are reflected in the EPA's quantification for that
state. In light of the fact that the building blocks are based on a
reasonable level of stringency and not the most stringent possible
level, the EPA expects that such offsetting emission reductions at the
state's affected EGUs from the application of other building blocks
will be available, so that the EPA will be able to finalize the state
goals as proposed. For example, a state's inability to meet the level
of emission reductions anticipated through use of one building block
may free up resources that the state could then devote to more
stringent implementation of another building block. This approach would
mean that overall, the same nationwide level of emission reductions as
proposed would be achieved. The EPA invites comment on this aspect of
the proposal.
At this time, the EPA is not proposing CO2 emission
performance goals for either Indian country or U.S. territories. The
EPA does plan to establish CO2 emission goals for both
Indian country and territories in the future. The EPA plans to conduct
additional outreach before setting these goals.
Issues related to the establishment of CO2 goals and CAA
section 111(d) plans for Indian country are discussed in Section V.D of
this preamble. As noted in that discussion, the EPA is aware of four
potentially affected power plants located in Indian country: The South
Point Energy Center, on Fort Mojave tribal lands within Arizona; the
Navajo Generating Station, on Navajo tribal lands within Arizona; the
Four Corners Power Plant, on Navajo tribal lands within New Mexico; and
the Bonanza Power Plant, on Ute tribal lands within Utah.\252\ Data for
these four power plants have been excluded from the data used to
compute the proposed state goals for Arizona, New Mexico, and Utah
discussed below.
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\252\ The South Point facility is an NGCC power plant, and the
Navajo, Four Corners, and Bonanza facilities are coal-fired power
plants.
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With respect to territories, the EPA is currently aware of
potentially affected EGUs in Puerto Rico, the U.S. Virgin Islands, and
Guam. The EPA requests comment on how the BSER would apply to these
territories, as well as to American Samoa or the Northern Mariana
Islands if potentially affected EGUs are subsequently identified in
those territories. In particular, the EPA solicits comment on
appropriate alternatives for territories that do not have access to
natural gas.\253\ Because the data sources we have used for purposes of
establishing renewable energy and demand-side energy efficiency targets
for states do not cover all the territories, we also solicit comment on
ways to determine appropriate renewable energy and demand-side energy
efficiency targets using other data sources.
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\253\ As noted in Section VI.C.5.d above, we are requesting
comment on whether heat rate improvements for non-coal fossil fuel-
fired EGUs should be part of the basis supporting the BSER, with
particular reference to the situation of geographically isolated
jurisdictions such as the U.S. territories.
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The remainder of this section addresses five sets of topics. First,
we discuss several issues related to the form of the goals. Second, we
describe the proposed state goals and the computation procedure. Third,
we discuss several types of state flexibility with respect to the
goals. Fourth, we describe the alternate set of goals offered for
comment and certain other approaches we considered. Finally, we discuss
the proposal's compatibility with the need to ensure a reliable,
affordable supply of electricity.
Some of the topics addressed in this section are addressed in
greater detail in supplemental documents available in the docket for
this rulemaking, including the Goal Computation TSD and the Greenhouse
Gas Abatement Measures TSD. Specific topics addressed in the various
TSDs are noted throughout the discussion below.
B. Form of Goals
The proposed goals are presented in the form of adjusted output-
weighted-average CO2 emission rates that the affected fossil
fuel-fired EGUs located in each state could achieve, on average,
through application of the measures
[[Page 34894]]
comprising the BSER (or alternative control methods). Several aspects
of this proposed form of goal are worth noting at the outset: The use
of an emission rate-based form (e.g., the quantity of CO2
per MWh of electricity generated), with the opportunity for the state
to adopt a mass-based form (e.g., a cap on the tonnage of
CO2 emissions); the use of output-weighted-average emission
rates for all affected EGUs in a state rather than nationally uniform
emission rates for all affected EGUs of particular types; the use of
adjustments to accommodate measures that reduce CO2
emissions by reducing the quantity of fossil fuel-fired generation
rather than by reducing the CO2 emission rate per MWh
generated by affected sources; the use of emission rates expressed in
terms of net rather than gross energy output; and the adjustability of
the goals based on the severability of the underlying building blocks.
First, the EPA proposes to use an emission rate-based form for the
state-specific goals included in the guidelines, and to give each state
the opportunity to translate its rate-based goal to an equivalent mass-
based form for state plan purposes. Each of the two forms of goals
presents advantages, and states have expressed support for having the
flexibility to use either form. Defining emission performance levels in
a rate-based form provides flexibility to accommodate changes in the
overall quantities of electricity generated in response to increases in
electricity demand. Defining emission performance levels in a mass-
based form provides relative certainty as to the absolute emission
levels that would be achieved as well as relative simplicity in
accommodating and accounting for the emission impacts of a wide variety
of emission reduction strategies. In light of these respective
advantages, we propose to set an emission rate-based form of goal, and
to allow any state to translate the rate-based goal to an equivalent
mass-based emission performance level for state plan purposes. This
approach allows each state to maximize the advantages it considers
optimal and is consistent with the state flexibility principle that is
central to the EPA's development of this program.
The second aspect noted above concerns the proposed choice of
state-specific output-weighted-average emission rates for all affected
EGUs in each state rather than nationally uniform emission rates for
particular types of affected EGUs. Here, the EPA's main consideration
has been to ensure that the proposed goals reflect opportunities to
manage CO2 emissions by shifting generation among different
types of affected EGUs. Specifically, because CO2 emission
rates differ widely across the fleet of affected EGUs, and because
transmission interconnections typically provide system operators with
choices as to which EGU should be called upon to produce the next MWh
of generation needed to meet demand, opportunities exist to manage
utilization of high carbon-intensity EGUs based on the availability of
less carbon-intensive generating capacity. For states and generators,
this means that CO2 emission reductions can be achieved by
shifting generation from EGUs with higher CO2 emission
rates, such as coal-fired EGUs, to EGUs with lower CO2
emission rates, such as NGCC units. Our analysis indicates that
shifting generation among EGUs offers opportunities to achieve large
amounts of CO2 emission reductions at reasonable costs.
These opportunities can be reflected in a goal established in the form
of an output-weighted-average emission rate for multiple affected EGU
types. Our approach is also consistent with the fact that the
proportions of different EGU types and hence the magnitudes of the
generation-shifting opportunities vary across states, and that CAA
section 111(d) calls for standards of performance to be established in
state plans rather than on a nationwide basis.
The third aspect noted above regarding the proposed form of the
goals concerns the adjustments made to the output-weighted-average
emission rates in order to accommodate reduced utilization of affected
EGUs associated with measures such as increases in low- and zero-carbon
generating capacity and demand-side energy efficiency. We recognize
that these measures support reduced overall CO2 mass
emissions from affected EGUs through reductions in the quantity of
generation from affected EGUs, and not necessarily through reductions
in the weighted-average CO2 emission rates of affected EGUs.
Accordingly, we have constructed the emission rate goals in a manner
that is intended to account for these generation quantity-reducing
measures by making adjustments to the values used in the emission rate
computations. The specific adjustments are summarized below in the
context of the goal computation methodology and are described in
greater detail in the Goal Computation TSD. As described below in
Section VIII on state plans, we are proposing that a state choosing a
rate-based form of goal would be able to make analogous adjustments
when assessing monitored emission performance so that measures that
support avoided generation at affected EGUs could be used to help the
state meet the rate-based emission performance level reflected in its
plan. We note that adjustments of this nature are not necessary when a
plan's emission performance level is based on the mass of
CO2 emissions \254\ rather than on CO2 emission
rates, because the emission-reducing effects of reduced generation at
affected EGUs are evident in the EGUs' reported CO2 mass
emissions.
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\254\ We also recognize that even under a mass-based approach,
adjustments may be appropriate in some circumstances to address
interstate effects, such as when measures undertaken pursuant to one
state's plan are expected to be associated with decreases in fossil
fuel-fired generation and CO2 emissions in another state.
These issues are discussed below in Section VIII on state plans.
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The fourth aspect noted above concerns the proposed expression of
the goals in terms of net energy output \255\--that is, energy output
encompassing net MWh of generation measured at the point of delivery to
the transmission grid rather than gross MWh of generation measured at
the EGU's generator.\256\ The difference between net and gross
generation is the electricity used at a plant to operate auxiliary
equipment such as fans, pumps, motors, and pollution control devices.
Because improvements in the efficiency of these devices represent
opportunities to reduce carbon intensity at existing affected EGUs that
would not be captured in measurements of emissions per gross MWh, we
are proposing goals expressed in terms of net generation. Nearly all
EGUs already have in place the equipment necessary to determine and
report hourly net generation, and we believe that the proposed
reporting requirement would therefore not be burdensome. However, we
also recognize that at present EGUs report gross rather than net load
\257\ to us under 40 CFR Part 75, and that the proposed GHG standards
of performance for new EGUs are expressed in terms of gross generation
(although we sought comment on the use of net generation instead). We
therefore specifically seek comment on whether the goals and reporting
requirements for existing EGUs should be expressed in terms of
[[Page 34895]]
gross generation instead of net generation for consistency with
existing reporting requirements and with the proposed requirements
under the GHG standards of performance for new EGUs.
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\255\ As discussed below in Section VIII on state plans, we are
similarly proposing that states choosing a rate-based form of
emission performance level for their plans should establish a
requirement for affected EGUs to report hourly net energy output.
\256\ For some EGUs, total net or gross energy output also
includes useful thermal output, in addition to either net or gross
electric energy output.
\257\ Some EGUs report gross steam output instead of gross
electrical load.
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The final aspect noted above has to do with the severability of the
four building blocks, discussed in Section VI above, upon which the
goals are based. Because the building blocks can be implemented
independently of one another and the goals are the sum of the emission
reductions from all of the building blocks, if any of the building
blocks is found to be an invalid basis for the ``best system of
emission reduction . . . adequately demonstrated,'' the goals would be
adjusted to reflect the emissions reductions from the remaining
building blocks. As noted above, the state goals that would result from
any combination of the building blocks can be computed from data
included in the Goal Computation TSD and its appendices using the
methodology described below and in that TSD.
We invite comment on all aspects of the proposed form of the goals.
C. Proposed Goals and Computation Procedure
The EPA has developed proposed goals for state plans reflecting
application of the BSER, based on all four building blocks described
earlier, to pertinent data for each state. The goals are intended to
represent CO2 emission rates achievable by 2030 after a
2020-2029 phase-in period on an output-weighted-average basis
collectively by all of a state's affected EGUs, with certain
computation adjustments described below to reflect the potential to
achieve mass emission reductions by avoiding fossil fuel-fired
generation. For each state, in addition to the final goal, the EPA has
developed an interim goal that would apply during the 2020-2029 period
on a cumulative or average basis as the state progresses toward the
final goal. The proposed goals are set forth in Table 8 below, followed
by a description of the computation methodology. (The issue of how
states could demonstrate emission performance consistent with the
interim and final goals is addressed in Section VIII on state plans.)
Table 8--Proposed State \258\ Goals
[Adjusted output-weighted-average pounds of CO2 per net MWh from all
affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
Interim Final
State goal goal
------------------------------------------------------------------------
Alabama............................................. 1,147 1,059
Alaska.............................................. 1,097 1,003
Arizona *........................................... 735 702
Arkansas............................................ 968 910
California.......................................... 556 537
Colorado............................................ 1,159 1,108
Connecticut......................................... 597 540
Delaware............................................ 913 841
Florida............................................. 794 740
Georgia............................................. 891 834
Hawaii.............................................. 1,378 1,306
Idaho............................................... 244 228
Illinois............................................ 1,366 1,271
Indiana............................................. 1,607 1,531
Iowa................................................ 1,341 1,301
Kansas.............................................. 1,578 1,499
Kentucky............................................ 1,844 1,763
Louisiana........................................... 948 883
Maine............................................... 393 378
Maryland............................................ 1,347 1,187
Massachusetts....................................... 655 576
Michigan............................................ 1,227 1,161
Minnesota........................................... 911 873
Mississippi......................................... 732 692
Missouri............................................ 1,621 1,544
Montana............................................. 1,882 1,771
Nebraska............................................ 1,596 1,479
Nevada.............................................. 697 647
New Hampshire....................................... 546 486
New Jersey.......................................... 647 531
New Mexico *........................................ 1,107 1,048
New York............................................ 635 549
North Carolina...................................... 1,077 992
North Dakota........................................ 1,817 1,783
Ohio................................................ 1,452 1,338
Oklahoma............................................ 931 895
Oregon.............................................. 407 372
Pennsylvania........................................ 1,179 1,052
Rhode Island........................................ 822 782
South Carolina...................................... 840 772
South Dakota........................................ 800 741
Tennessee........................................... 1,254 1,163
Texas............................................... 853 791
Utah *.............................................. 1,378 1,322
Virginia............................................ 884 810
Washington.......................................... 264 215
West Virginia....................................... 1,748 1,620
Wisconsin........................................... 1,281 1,203
Wyoming............................................. 1,808 1,714
------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.
---------------------------------------------------------------------------
\258\ The EPA has not developed goals for Vermont and the
District of Columbia because current information indicates those
jurisdictions have no affected EGUs. Also, as noted above, the EPA
is not proposing goals for Indian country or U.S. territories at
this time.
---------------------------------------------------------------------------
The proposed goals are expressed as adjusted output-weighted-
average emission rates for all affected EGUs in a state. As discussed
earlier in this section, a goal expressed as an unadjusted output-
weighted-average emission rate would fail to account for mass emission
reductions from reductions in the total quantity of fossil fuel-fired
generation associated with state plan measures that increase low- or
zero-carbon generating capacity or demand-side energy efficiency.
Accordingly, under the proposed goals, the emission rate computation
includes an adjustment designed to reflect those mass emission
reductions. The adjustment is made by estimating the annual net
generation associated with an achievable amount of qualifying new low-
carbon and zero-carbon generating capacity, as well as the annual
avoided generation associated with an achievable portfolio of demand-
side energy efficiency measures, and adding those MWh amounts to the
energy output from affected units that would have been used in an
unadjusted output-weighted-average emission rate computation.\259\
Mathematically, this adjustment has the effect of spreading the
measured CO2 emissions from the state's affected EGUs over a
larger quantity of energy output, thus resulting in an adjusted
emission rate lower than the unadjusted emission rate. (As discussed
below in Section VIII on state plans, we are proposing that a state
could make analogous adjustments to compliance measurement approaches
under its state plan, thereby enabling the state to adopt an emission
rate-based form of emission performance level while still being able to
rely on low- or zero-carbon capacity deployment programs and demand-
side energy efficiency as components of its plan.)
---------------------------------------------------------------------------
\259\ In the case of new capacity that is not zero-carbon, an
adjustment would also be required to the emissions value used in
computing the weighted-average emission rate. This procedure is
discussed further in the Goal Computation TSD.
---------------------------------------------------------------------------
The methodology used to compute each state's proposed goal is
summarized on a step-by-step basis below. The methodology is described
in more detail in the Goal Computation TSD, which includes a numerical
example illustrating the full procedure. The development of the data
inputs used in the computation procedure is discussed in Section VI
above and in the Greenhouse Gas Abatement Measures TSD.
Step 1 (compilation of baseline data). On a state-by-state basis,
we obtained total annual quantities of CO2 emissions, net
generation (MWh), and capacity (MW) from reported 2012 data for all
affected EGUs.\260\ For each state,
[[Page 34896]]
we aggregated the 2012 data for all coal-fired steam EGUs as one group,
all oil- and gas-fired steam EGUs as a second group, and all NGCC units
as a third group. We aggregated the 2012 data for all remaining
affected EGUs (i.e., integrated gasification combined-cycle (IGCC)
units and any simple-cycle combustion turbines satisfying relevant
thresholds for qualification as affected EGUs) as a fourth, ``other''
group.\261\ To these totals for affected EGUs operating in 2012, we
added estimates for other EGUs not yet in operation in 2012 that are
affected EGUs for purposes of this emission guideline.\262\ Capacity
and emission rate data inputs for the post-2012 affected EGUs were
obtained from the NEEDS database maintained by the EPA for use with the
Integrated Planning Model (IPM). Generation data inputs for the post-
2012 affected EGUs were estimated based on the average 2012 utilization
rates for recently constructed EGUs of the same types; for example, we
estimated in this step that the post-2012 NGCC units would operate at a
55 percent utilization rate on average.
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\260\ EGUs whose capacity, fossil fuel combustion, or
electricity sales were insufficient to qualify them as affected EGUs
were not included in the goal computations. Most simple cycle
combustion turbines were excluded on this basis. See the
applicability criteria described in Section V.B. above.
\261\ The emission and generation totals for the ``other'' group
also reflect the portion of affected cogeneration units' total
CO2 emissions and total energy output corresponding to
those units' useful thermal output.
\262\ Assuming it meets other applicability criteria, an EGU
would be affected if it had commenced construction by January 8,
2014 (the data of Federal Register publication of the proposed GHG
NSPS for new EGUs).
---------------------------------------------------------------------------
Step 2 (application of building block 1). The total CO2
emissions amount for the coal-fired steam EGU group in each state from
Step 1 was reduced by six percent, reflecting our assessment of the
average opportunity to reduce CO2 emission rates across the
existing fleet of coal-fired steam EGUs through heat rate improvements
that is technically achievable at a reasonable cost.
Step 3 (application of building block 2). If the generation data
for the NGCC group in a state developed in Step 1 showed average annual
utilization below 70 percent of those units' maximum possible output,
and the generation data developed in Step 1 also included generation
from the coal-fired steam or oil/gas-fired steam EGU groups in that
state, the generation and emissions figures for the NGCC group were
increased, and the generation and emissions figures for the coal-fired
and oil/gas-fired steam EGU groups from Step 2 were proportionately
\263\ decreased, to reflect an estimated potential increase in
utilization of the NGCC group to a maximum of 70 percent. In this step,
the total (across all four groups) of the state's fossil fuel-fired
generation was maintained at the amount computed in Step 1, but to the
extent that in the analysis a portion of the total fossil generation
was shifted from the coal-fired and oil/gas-fired steam EGU groups,
which have higher CO2 emission rates, to the NGCC group,
which has a lower CO2 emission rate, the total (across all
four groups) of the state's CO2 emissions was reduced.\264\
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\263\ For example, if the data developed in Step 1 showed equal
quantities of MWh generated by the coal-fired steam EGU group and
the oil/gas-fired steam EGU group, then any overall reduction in the
MWh generated by these two groups due to a commensurate increase in
the MWh generated by the less carbon-intensive NGCC group would be
split equally between the coal-fired steam group and the oil/gas-
fired steam group.
\264\ We did not estimate any change in utilization, generation,
or emissions for the state's ``other'' group of IGCC units and
simple-cycle combustion turbines in Step 3.
---------------------------------------------------------------------------
Step 4 (application of building block 3). We estimated the total
quantities of generation from renewable generating capacity and from
under-construction or preserved nuclear capacity for each state using
the approaches described in Section VI.C.3 above. Separate estimates of
renewable generation were computed for each year of the plan period for
each state based on the state's 2012 renewable generation and a
regional growth factor. Nuclear generation was estimated as the amount
of under-construction and preserved nuclear capacity for each state
operated at a utilization rate of 90 percent, consistent with recent
industry-wide average utilization rates for nuclear units.
Step 5 (application of building block 4). We estimated the total
MWh amount by which generation from each state's affected EGUs would be
cumulatively reduced in each year of the plan period associated with
implementation in that state of demand-side energy efficiency programs
resulting in annual incremental reductions in the state's electricity
usage (relative to usage absent those programs) of 1.5 percent each
year, as described in Section VI.C.4 above. Separate estimates were
developed for each year to reflect the fact that energy efficiency
programs that are implemented on an ongoing basis would be expected to
produce larger cumulative impacts on total annual electricity usage
over time. For states that are net importers of electricity, the
estimated reduction in the generation by the state's affected EGUs was
scaled down to reflect an expectation that a portion of the generation
avoided by the demand-side energy efficiency would occur at EGUs in
other states.
Step 6 (computation of annual rates). We computed adjusted output-
weighted-average CO2 emission rates for each state by
dividing (1) the total CO2 emissions for the coal-fired
steam EGU, oil- and gas-fired steam EGU, NGCC unit, and ``other''
affected fossil EGU groups from Step 3 above by (2) the total of (a)
the total net energy output (expressed in MWh) for the four groups from
Step 1 above plus (b) the estimated annual net generation from
renewable and nuclear generating capacity from Step 4 above plus (c)
the estimated cumulative annual MWh amount saved through demand-side
energy efficiency from Step 5 above.\265\ We performed these
computations separately for each year from 2020 to 2029, using the
respective cumulative annual MWh savings figures developed in Steps 4
and 5.
---------------------------------------------------------------------------
\265\ Expressed as a formula, the equation for the annual rate
computation is:
[(Coal gen. x Coal emission rate) + (OG gen. x OG emission rate)
+ (NGCC gen. x NGCC emission rate) + ``Other'' emissions]/[Coal gen.
+ OG gen. + NGCC gen. + ``Other'' gen. + Nuclear gen. + RE gen. + EE
gen.]
This formula and its elements are further explained in the Goal
Computation TSD, as well as in the text above.
---------------------------------------------------------------------------
Step 7 (computation of interim and final goals). The final 2030
goal for each state is the annual rate computed for 2029 for the state
from Step 6 above. We computed the 2020-2029 interim goal for each
state as the simple average of the annual rates computed for each of
the years from 2020 to 2029 for the state from Step 6 above.
It bears emphasis that the procedure described above is proposed to
be used only to determine state goals, and the particular data inputs
used in the procedure are not intended to represent specific
requirements that would apply to any individual EGU or to the
collection of EGUs in any state. The specific requirements applicable
to individual EGUs, to the EGUs in a given state collectively, or to
other affected entities in the state, would be based on the standards
of performance established through that state's plan. The details of
how states could attain emission performance levels consistent with the
goals through different state plan approaches that recognize emission
reductions achieved through all the building blocks are discussed
further in Section VIII on state plans.
We invite comment on all aspects of the goal computation procedure.
(Note that we also invite comment on certain specific alternate data
inputs to the procedure in Section VI.C above.) We also specifically
invite comment on the state-specific historical data to which
[[Page 34897]]
the building blocks are applied in order to compute the state goals, as
well as the state-specific data used to develop the state-specific data
inputs for building blocks 3 and 4. These data are contained in the
Goal Computation TSD and the Greenhouse Gas Abatement Measures TSD.
With respect to building block 2, we specifically request comment
on the following alternate procedure: In Step 3, to the extent that
generation from a state's NGCC group was increased consistent with the
NGCC utilization rate target, in order to maximize the resulting
emission reductions, we would decrease generation from the state's
coal-fired steam group first, and then decrease generation from the
state's oil/gas-fired steam group (instead of decreasing generation
from the coal-fired steam and oil/gas-fired steam groups
proportionately).
With respect to building block 4, we specifically invite comment on
the alternative in Step 5 of scaling up the estimated reduction in the
generation by affected EGUs in net electricity-exporting states to
reflect an expectation that a portion of the generation avoided in
conjunction with the demand-side energy efficiency efforts of other,
net electricity-importing states would occur at those EGUs, analogous
to the proposed adjustment for net electricity-importing states
described in Step 5. We also request comment on the alternative of
making no adjustment in Step 5 for either net electricity-importing or
net electricity-exporting states. These alternatives are discussed in
the Goal Computation TSD.
We also request comment on whether CO2 emission
reductions associated with other measures not currently included in any
of the four proposed building blocks should be included in the state
goals.
D. State Flexibilities
As promulgated in the final rule following consideration of
comment, the state-specific goals will be binding emission guidelines.
States' ability to achieve emission performance levels consistent with
the binding goals is enhanced by several distinct types of flexibility:
(i) Choices as to the measures employed, including the timing of their
implementation; (ii) the ability to translate from a rate-based form of
goal to a mass-based form of goal; and (iii) the opportunity to pursue
multi-state plan approaches.
First, a core flexibility provided under CAA section 111(d) is that
while states are required to establish standards of performance that
reflect the degree of emission limitation from application of the
control measures that the EPA identifies as the BSER, they need not
mandate the particular control measures the EPA identifies as the basis
for its BSER determination. In developing the building block data
inputs applied to each state's historical data to develop the goals,
the EPA targeted reasonably achievable rather than maximum performance
levels. The overall goals therefore represent reasonably achievable
emission performance levels that provide states with flexibility to
pursue some building blocks more extensively and others less
extensively than the degree reflected in the EPA's data inputs while
meeting the overall goals. States can also choose to include in their
plans other measures that reduce CO2 emissions at affected
EGUs but that are not included in the building blocks.
Further, by allowing states to demonstrate emission performance by
affected EGUs on an average basis over a multi-year interim plan period
of as long as ten years, the EPA's proposed approach increases states'
flexibility to choose among alternative potential plan measures. For
example, by taking advantage of the multi-year flexibility, a state
could choose to rely more heavily in its plan on measures whose
effectiveness tends to grow over time, such as demand-side energy
efficiency programs. This flexibility could also help states address
concerns about stranded assets, for example, by enabling states to
defer imposition of requirements on EGUs that may be scheduled to
retire after 2020 but before 2029.
The second type of flexibility noted above is that while the EPA is
proposing to establish goals in an emission rate-based form, we are
also proposing to provide states with the flexibility to translate the
rate-based goals to mass-based goals in order to accommodate states'
potential interest in having emission performance requirements measured
in absolute tons. For example, the northeastern and Mid-Atlantic states
that currently participate in the mass-based Regional Greenhouse Gas
Initiative (RGGI) may choose to develop state plans (or a multi-state
plan, as noted below) establishing mass-based emission performance
levels designed to be met at least in part through standards of
performance based on RGGI's existing market-based CO2
emission budget trading program. Because the use of mass-based plans
can simplify the process of accounting for the CO2 reduction
impacts of a variety of measures, the EPA believes the flexibility to
adopt mass-based emission performance levels can facilitate plan
development and could be attractive to states that do not already
participate in mass-based emission reduction programs as well.
Third, the EPA's approach allows states to submit multi-state
plans. The EPA expects this flexibility to reduce the cost of achieving
the state goals and therefore expects it to be attractive to states.
For example, the RGGI-participating states could choose to submit a
multi-state mass-based plan that demonstrates emission performance by
affected EGUs on a multi-state basis. Additional states may also choose
to join a multi-state plan. The mechanics of translating rate-based
goals into mass-based goals and considerations related to multi-state
plans are discussed below in Section VIII on state plans.
Some stakeholders have suggested that states themselves should be
allowed to quantify the level of emission reduction resulting from the
application of BSER or, if the EPA establishes goals, the states should
be allowed to adjust the goals or to treat the goals established by the
EPA as advisory rather than binding. Consistent with the existing
implementing regulations for CAA section 111(d) at 40 CFR part 60, this
quantification is the EPA's role.\266\ As discussed in the Legal
Memorandum, CAA section 111(d) directs the EPA to ``prescribe
regulations which shall establish a procedure similar to that provided
by [CAA section 110] under which each State shall submit'' a section
111(d) state plan. As noted in Section II.D of this preamble, the EPA
promulgated implementing regulations in 1975, and has revised parts of
them since. The regulations set out a multi-step process for the
development and approval of state plans, and assign responsibility for
the various steps in the process to the EPA or the states. The
regulations provide that the EPA is to promulgate an ``emission
guideline that reflects the application of the best system of emission
reduction (considering the cost of such reduction) that has been
adequately demonstrated for'' affected sources.\267\ In this manner,
the regulations make clear that the EPA determines the BSER. In this
rulemaking, as discussed above, the EPA identifies the BSER. In
addition, in this rulemaking, the EPA applies the BSER to each state,
and then, for each state, calculates the average emission rate that, in
the words of the regulations just quoted, ``reflects the application of
[[Page 34898]]
the [BSER].'' That average emission rate is the state goal.
---------------------------------------------------------------------------
\266\ 40 CFR 60.22(b)(5). We do not propose to re-open that
portion of the implementing regulations in this rulemaking.
\267\ Id.
---------------------------------------------------------------------------
By the same token, because the state goals are an integral part of
the emission guidelines that the framework regulations authorize the
EPA to establish, the goals are binding, and the states, in their CAA
section 111(d) plans, must meet those goals and may not make them less
stringent. This matter, too, is resolved by the implementing
regulations.\268\ To reiterate, the proposed state goals represent the
level of performance that is achievable through application of the BSER
to the pertinent data for each individual state. States have the
opportunity to comment on the proposed BSER, the proposed methodology
for computing state goals based on application of the BSER, and the
state-specific data that is proposed for use in the computations. We
expect that the states will have an adequate opportunity to comment on
the state goals during the comment period. Once the final goals have
been promulgated, and adjusted as may be appropriate based on comments
to address any factual errors in the analysis, the states will be able
to meet them because they will represent the application of BSER to the
states' affected sources. In addition, states have several types of
flexibilities in developing their state plans: They have flexibility
regarding the selection of the measures upon which they choose to rely
and a 10-year time period over which to reach full implementation of
these measures, and they can use rate-based or mass-based approaches.
In addition, as we have noted, multi-state coordination offers states
an opportunity to achieve additional emission reductions and reduce
implementation costs. These flexibilities, discussed further in Section
VIII of this preamble, ensure that states will be able to achieve their
final CO2 emission performance goals and that no special
provision for state adjustment of goals outside the normal notice-and-
comment rulemaking process is warranted.\269\
---------------------------------------------------------------------------
\268\ Id. We do not propose to re-open that portion of the
implementing regulations in this rulemaking.
\269\ In the event that a state becomes concerned about its
ability to meet the goal that the EPA promulgates for it, the state
may submit to the EPA a petition for reconsideration, if that
petition is based on relevant information not available during the
comment period. See CAA section 307(d)(7)(B).
---------------------------------------------------------------------------
E. Alternate Goals Offered for Comment and Other Approaches Considered
In addition to the proposed state-specific emission rate-based
goals described above, the EPA has developed for public comment an
alternate set of goals reflecting less stringent application of the
building blocks and a shorter implementation period. The alternate
final goals represent emission performance that would be achievable by
2025, after a 2020-2024 phase-in period, with interim goals that would
apply during the 2020-2024 period on a cumulative or average basis as
states progress toward the final goals.
Because the time period for implementation relates directly to the
emission reductions that are achievable and therefore what measures,
and at what level of stringency, constitute the BSER, the alternate
goals reflect several differences in data inputs from the proposed
goals. Specifically, a value of four percent (instead of six percent)
was used for the potential improvement in carbon intensity of coal-
fired EGUs in Step 2; a value of 65 percent (instead of 70 percent) was
used for the potential annual utilization rate of NGCC units in Step 3;
and a value of one percent (instead of 1.5 percent) was used for the
annual incremental electricity savings achievable through a portfolio
of demand-side energy efficiency programs in Step 5. (No change was
made to the data inputs regarding less carbon-intensive generating
capacity in Step 4.) As noted above, the alternate goals also reflect a
shortening of the proposed phase-in period from ten years (2020-2029)
to five years (2020-2024) to reflect an expectation that less stringent
goals could be achieved in less time. Steps 5, 6, and 7 of the goal
computation procedure therefore were performed for the span of years
from 2020 to 2024 rather than for the span from 2020 to 2029. The
alternate goals are set forth in Table 9 below.
Table 9--Alternate State \270\ Goals
[Adjusted output-weighted-average pounds of CO2 per net MWh from all
affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
Interim Final
State goal goal
------------------------------------------------------------------------
Alabama............................................. 1,270 1,237
Alaska.............................................. 1,170 1,131
Arizona *........................................... 779 763
Arkansas............................................ 1,083 1,058
California.......................................... 582 571
Colorado............................................ 1,265 1,227
Connecticut......................................... 651 627
Delaware............................................ 1,007 983
Florida............................................. 907 884
Georgia............................................. 997 964
Hawaii.............................................. 1,446 1,417
Idaho............................................... 261 254
Illinois............................................ 1,501 1,457
Indiana............................................. 1,715 1,683
Iowa................................................ 1,436 1,417
Kansas.............................................. 1,678 1,625
Kentucky............................................ 1,951 1,918
Louisiana........................................... 1,052 1,025
Maine............................................... 418 410
Maryland............................................ 1,518 1,440
Massachusetts....................................... 715 683
Michigan............................................ 1,349 1,319
Minnesota........................................... 1,018 999
Mississippi......................................... 765 743
Missouri............................................ 1,726 1,694
Montana............................................. 2,007 1,960
Nebraska............................................ 1,721 1,671
Nevada.............................................. 734 713
New Hampshire....................................... 598 557
New Jersey.......................................... 722 676
New Mexico *........................................ 1,214 1,176
New York............................................ 736 697
North Carolina...................................... 1,199 1,156
North Dakota........................................ 1,882 1,870
Ohio................................................ 1,588 1,545
Oklahoma............................................ 1,019 986
Oregon.............................................. 450 420
Pennsylvania........................................ 1,316 1,270
Rhode Island........................................ 855 840
South Carolina...................................... 930 897
South Dakota........................................ 888 861
Tennessee........................................... 1,363 1,326
Texas............................................... 957 924
Utah *.............................................. 1,478 1,453
Virginia............................................ 1,016 962
Washington.......................................... 312 284
West Virginia....................................... 1,858 1,817
Wisconsin........................................... 1,417 1,380
Wyoming............................................. 1,907 1,869
------------------------------------------------------------------------
* Excludes EGUs located in Indian country in the state.
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\270\ See footnote accompanying Table 8 above.
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The EPA recognizes that its approach to the alternate goals,
comprising less stringent requirements in each of the building blocks
to be achieved over a shorter compliance horizon, follows the logic of
including time as one of the functions of the BSER determination. At
the same time, we also recognize that the components of the alternate
goals may reflect an overly conservative approach. Specifically, the
alternate goals as set forth above may underestimate the extent to
which the key elements of the four building blocks--achieving heat rate
improvements at EGUs, switching generation to NGCC facilities,
fostering the penetration of renewable resources or improving year-to-
year end-use energy efficiency--can be achieved rapidly while
preserving reliability and remaining reasonable in cost. Accordingly,
we request comment on the alternate goals, particularly with respect to
whether any one or all of the building blocks in the alternate goals
[[Page 34899]]
can be applied at a greater level of stringency: Can the heat rate
improvement value be set at a level above four percent, even six
percent? Can NGCC capacity be dispatched at a utilization rate above 65
percent? Can annual incremental electricity savings be achieved at a
rate higher than one percent?
It is worth noting that the EPA projects that the alternate goals
will achieve emission reductions equal to 23 percent below 2005 level
in 2025. The EPA's analysis shows that under the proposed goals
described in Section VII.C above, power sector emissions will be 29
percent below 2005 levels in 2025, suggesting that the kinds of changes
contemplated in the four building blocks, even as early as 2025, will
be yielding reductions far greater than the 23 percent projected for
the alternate goals as set forth above in this subsection.
The EPA has considered other approaches to setting goals. In
particular, given the interconnected nature of the power sector and the
importance of opportunities for shifting generation among EGUs, we
considered whether goals should be set on a multi-state basis
reflecting the scope of existing regional transmission control areas.
We also considered whether goals should be set on a state-specific
basis, but regional rather than state-specific evaluations should be
used to assess the estimated opportunities to reduce utilization of the
most carbon-intensive EGUs by shifting generation to less carbon-
intensive EGUs. A potential advantage of using regional evaluations is
the ability to recognize additional emission reduction opportunities
that would be available at reasonable costs based on a more complete
representation of the capabilities of existing infrastructure to
accommodate shifts in generation among EGUs in multiple states. We
request comment on whether, and if so how, the EPA should incorporate
greater consideration of multi-state approaches into the goal-setting
process, and on the issue of whether, and if so how, the potential cost
savings associated with multi-state approaches should be considered in
assessing the reasonableness of the costs of state-specific goals.
F. Reliable Affordable Electricity
Many stakeholders raised concerns that this regulation could affect
the reliability of the electric power system. The EPA agrees that
reliability must be maintained and in designing this proposed
rulemaking has paid careful attention to this issue. The EPA has met on
several occasions with staff and managers from the Department of Energy
and the Federal Energy Regulatory Commission to discuss our approach to
the rule and its potential impact on the power system. EPA staff and
managers have also had numerous discussions with state public utility
commissioners and their staffs to get their suggestions and advice
concerning this rule, including how to address reliability concerns.
In addition, the EPA met with independent system operators several
times to discuss any potential impact of this rule on grid reliability.
The ISO/RTO Council, a national organization of electric grid
operators, offered analytic support to help states design programs that
do not compromise the regional bulk power system. They also offered to
help states develop regional approaches which may reduce costs and
strengthen the reliability of the electricity grid. Specifically, the
ISO/RTO Council has suggested that ISOs and RTOs could provide analytic
support to help states develop and implement their plans. The ISOs and
RTOs have the capability to model the system-wide effects of individual
state plans. Providing assistance in this way, they felt, would allow
states with borders that fall within an ISO or RTO footprint to assess
the system-wide impacts of potential state plan approaches. In
addition, as the state implements its plan, ISO/RTO analytic support
would allow the state to monitor the effects of its plan on the
regional electricity system. ISO/RTO analytic capability could help
states assure that their plans are consistent with region-wide system
reliability. The ISO/RTO Council suggested that the EPA ask states to
consult with the applicable ISO/RTO in developing their state plans.
The EPA agrees with this suggestion and encourages states with borders
that fall within one or more ISO or RTO footprints to consult with the
relevant ISOs/RTOs.
The EPA has met with the U.S. Department of Agriculture as well to
discuss how we can address the concerns of small, relatively isolated
power generators in rural America and especially the electric
cooperatives. Many of these entities have special challenges, as they
may have small, older carbon-intensive assets and might have particular
challenges meeting carbon requirements.
With all of this in mind, the EPA in determining the BSER looked
specifically at the reasonableness of the costs of control options in
part to ensure that the options would not have a negative effect on
system reliability. The BSER, including each of the building blocks,
was determined to be feasible at reasonable costs over the timeframe
proposed here. Further, under the Clean Air Act the states are given
the flexibility to design state plans that include any measure or
combination of measures to achieve the required emission limitations.
States are not required to use each of the measures that the EPA
determines constitute the BSER or use those measures to the same degree
or extent that the EPA determines is feasible at a reasonable cost.
Thus, each state has the flexibility to choose the most cost-effective
measures given that state's energy profile and economy, as long as the
state achieves the reductions necessary to meet its goal. Many market-
based approaches which states may choose reduce the costs of
compliance. They can allow certain units that are seldom used to remain
in operation if they are needed for reliability purposes. Multi-state
approaches also reduce costs and stress on the grid and so can help to
reduce any concern about electricity reliability.
States may choose measures that would ease pressures on system
reliability. This is true for many demand-side management approaches,
including programs to encourage end-use energy efficiency, distributed
generation, and combined heat and power, which actually reduce demand
for centrally generated power and thus relieve pressure on the grid.
The EPA is proposing a 10-year period over which to achieve the
full required CO2 reductions, and we would expect this to
further relieve any pressure on grid reliability. This relatively long
planning and implementation period provides states with substantial
flexibility regarding methods and timing of achieving emission
reductions.
The EPA's supporting analysis for this rule includes an examination
of the effects of the rule on regional resource adequacy.\271\ The
EPA's analysis looked at the types of changes in the generation fleet
that were projected to occur through retirements, additional generation
and energy efficiency. The analysis did not raise concerns over
regional resource adequacy. The EPA further examined how the policy
options impacted the flows and transfers of electricity that occur to
meet reserve margins. None of the interregional changes in the policy
cases suggested that there would be increases in flows that would raise
significant concerns about grid congestion or grid management.
Moreover, the time
[[Page 34900]]
horizon for compliance with this rule will permit environmental and
reliability planners to coordinate these changes and address potential
concerns before they arise.
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\271\ See the Resource Adequacy and Reliability Analysis TSD,
available in the docket.
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The EPA concludes that the proposed rule will not raise significant
concerns over regional resource adequacy or raise the potential for
interregional grid problems. The EPA believes that any remaining local
issues can be managed through standard reliability planning processes.
The flexibility inherent in the rule is responsive to the CAA's
recognition that state plans for emission reduction can, and must, be
consistent with a vibrant and growing economy and reliable, affordable
electricity to support that economy. The EPA welcomes comments and
suggestions on this issue.
VIII. State Plans
A. Overview
After the EPA establishes the state-specific rate-based
CO2 goals in the emission guidelines, as described in
Section VII above, each state must then develop, adopt, and submit its
state plan under CAA section 111(d). To do so, the state must first
determine the emission performance level it will include in its plan,
which entails deciding whether it will adopt the rate-based
CO2 goal set by the EPA or translate the rate-based goal to
a mass-based goal.
The state must then establish an emission standard or set of
emission standards, and, perhaps other measures, along with
implementing and enforcing measures, that will achieve a level of
emission performance that is equal to or better than the level
specified in the state plan.
The state must then adopt the state plan through certain
procedures, which include a state hearing. Within the time period
specified in the emission guidelines (from as early as June 30, 2016 to
as late as June 30, 2018, depending on the state's circumstances), the
state must submit its complete state plan to the EPA. The EPA then must
determine whether to approve or disapprove the plan. If a state does
not submit a plan, or if the EPA does not approve a state's plan, then
the EPA must establish a plan for the state.
As discussed in Section V.D of this preamble, in the case of a
tribe that has one or more affected EGUs located in its area of Indian
country, if the EPA determines that a CAA section 111(d) plan is
necessary or appropriate, the EPA has the responsibility to establish a
CAA section 111(d) plan for that area of Indian country where affected
sources are located unless the tribe on whose lands an affected source
(or sources) is located seeks and obtains authority from the EPA to
establish a plan itself, pursuant to the Tribal Authority Rule.\272\
The agency is soliciting comment on aspects of such CAA section 111(d)
plans, as described in Section V.D of this preamble.
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\272\ See 40 CFR 49.1 to 49.11.
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This section is organized into six parts. First, we discuss the
types of plans that we propose states could submit. Second, we address
timing for plan implementation and achievement of state emission
performance goals for affected EGUs. Third, we discuss the proposed
state plan approvability criteria. Fourth, we summarize the proposed
components of an approvable state plan. Fifth, we address the proposed
process and timing for submittal of state plans. Sixth, we identify
several key considerations for states in developing and implementing
plans, including: Affected entities with obligations under a plan;
treatment of existing state programs; incorporation of renewable energy
(RE) and demand-side energy efficiency (EE) programs in certain plans;
quantification, monitoring, and verification of RE and demand-side EE
measures; reporting and recordkeeping for affected entities; treatment
of interstate effects; and projection of emission performance. Finally,
we discuss a number of additional factors that could help states meet
their CO2 emission performance goals, and we note certain
resources that are available to facilitate plan development and
implementation. Additional discussion of some of the topics covered in
this section can be found in the State Plan Considerations TSD and
Projecting EGU CO2 Emission Performance in State Plans TSD,
both of which are in the rulemaking docket.
B. Approach
In this action, the EPA is proposing emission guidelines in the
form of state-specific CO2 emission performance goals. In
addition, the EPA is proposing guidelines for states to follow in
developing plans to establish and implement CO2 emission
standards for affected EGUs. The proposed plan guidelines include four
general plan approvability criteria, twelve required components for a
state plan to be approvable, the process and timing for state plan
submittal and review, and the process and timing for demonstrating
achievement of the CO2 goals. These are described below.
The EPA recognizes that each state has different state policy
considerations--including varying emission reduction opportunities and
existing state programs and measures--and that the characteristics of
the electricity system in each state (e.g., utility regulatory
structure, generation mix, electricity demand) also differ. The agency
also anticipates--and supports--states' commitments to a wide range of
policy preferences that could encompass those of states like Kentucky,
West Virginia and Wyoming seeking to continue to feature significant
reliance on coal-based generation; states like Minnesota, Colorado,
California and the nine RGGI states seeking to build on actions and
policies they have already undertaken; and states like Washington and
Oregon seeking to integrate sustainable forestry and renewable energy
strategies. The proposed plan guidelines provide states with options
for establishing emission standards in a manner that accommodates a
diverse range of state approaches. Each state will have significant
flexibility to determine how to best achieve its CO2 goals
in light of its specific circumstances, including addressing concerns
particular to the state, such as employment transition issues, as it
designs and implements its plan over multiple years. As an example, the
RGGI states' implementation of their mass-based emission budget trading
program raises proceeds through allowance auctions and uses those
proceeds to advance programs promoting and expanding end-use energy
efficiency. States could address analogous priorities, such as
employment transition, through a similar mechanism.
The proposed plan guidelines would also allow states to collaborate
and to develop plans that provide for demonstration of emission
performance on a multi-state basis, in recognition of the fact that
electricity is transmitted across state lines, and that state measures
may impact, and may be explicitly designed to reduce, regional EGU
CO2 emissions. The EPA also recognizes that multi-state
collaboration would likely offer lower-cost approaches to achieving
CO2 emission reductions. With this in mind, we are proposing
to provide states with additional time to submit complete plans if they
do so as part of a multi-state plan, and we solicit comment on other
potential mechanisms for fostering multi-state collaboration.
1. State Plan Approaches
a. Overview
Although state CAA section 111(d) plans must assure that the
emission performance level is achieved through
[[Page 34901]]
reductions at the affected sources, we believe that different types of
state plans could be constructed that make use of the diversity of
measures available to achieve CO2 emission reductions. Based
on the EPA's outreach efforts, it is clear that states are considering
different types of plans.
Three important issues in the design of state plans include: (1)
Whether the plan should require the affected EGUs to be subject to
emission limits that assure that the emission performance level is
achieved, or instead, whether the plan could rely on measures, such as
renewable energy (RE) or demand-side energy-efficiency (EE), to assure
the achievement of part of the emission performance level; (2) whether
the responsibility for all of the measures other than emission limits
should fall on the affected EGUs, or, instead, could fall on entities
other than affected EGUs; and (3) whether the fact that requiring all
measures relied on to achieve the emission performance level to be
included in the state plan renders those measures federally
enforceable. These issues and the EPA's proposed approach are addressed
in detail in the sections that follow.
The EPA is proposing that all measures relied on to achieve the
emission performance level be included in the state plan, and that
inclusion in the state plan renders those measures federally
enforceable.
In light of current state programs, and of stakeholder expressions
of concerns over the above-noted issues, including legal enforcement
considerations, with respect to those programs, the EPA is proposing to
authorize states either to submit plans that hold the affected EGUs
fully and solely responsible for achieving the emission performance
level, or to submit plans that rely in part on measures imposed on
entities other than affected EGUs to achieve at least part of that
level, as well as on measures imposed on affected EGUs to achieve the
balance of that level. The EPA requests comment on this proposed
approach, as opposed to the approach under which state plans simply
would be required to hold the affected EGUs fully and solely
responsible for achieving the emission performance level.
In addition, the EPA is soliciting comment on several other types
of state plans that may assure the requisite level of emission
performance without rendering certain types of measures federally
enforceable and that limit the obligations of the affected EGUs.
b. Portfolio Approach
In assessing the types of state plans to authorize, the EPA
reviewed existing state programs that reduce CO2 emissions
from fossil fuel-fired power plants. Existing state programs are
particularly informative for this purpose in light of the fact that CAA
section 111(d) gives states the primary responsibility for designing
their own state plans for submission to the EPA. Many of these existing
state programs, as summarized above, include measures such as renewable
energy (RE) and demand-side energy efficiency (EE) programs, which
impose responsibilities on a range of entities, including state
agencies, for assuring implementation of actions that result in reduced
utilization of, and therefore reduced emissions from, fossil fuel-fired
EGUs, and do not impose legal responsibilities for those emission
reductions on the EGUs themselves.
In addition, during the EPA's extensive outreach efforts, many
stakeholders expressed concern over the extent of responsibility that
fossil fuel-fired EGUs would be required to bear for the required
emission reductions, in particular, those associated with RE and
demand-side EE measures. These stakeholders recommended that the EPA
authorize states to achieve emission reductions from RE and demand-side
EE measures by imposing requirements on entities other than fossil
fuel-fired EGUs, and without imposing legal responsibility for these
emission reductions on those EGUs.
Accordingly, the EPA is proposing to authorize a state plan to
adopt what we refer to as a ``portfolio approach,'' in which the plan
would include emission limits for affected EGUs along with other
enforceable measures, such as RE and demand-side EE measures, that
reduce CO2 emissions from affected EGUs. Under this
approach, it would be all of the measures combined that would be
designed to achieve the required emission performance level for
affected EGUs as expressed in the state goal. Under this approach, the
emission limits enforceable against the affected EGUs would not, on
their own, assure, or be required to assure, achievement of the
emission performance level. Rather, the state plan would include
measures enforceable against other entities that support reduced
generation by, and therefore CO2 emission reductions from,
the affected EGUs. As noted, these other measures would be federally
enforceable because they would be included in the state plan. A
portfolio approach could be used for state plans that establish the
emission performance level on either an emission rate basis or a mass
emissions basis.
In addition, a portfolio approach could either be what we refer to
as ``utility-driven'' or ``state-driven,'' depending on the utility
regulatory structure in a state. Under a utility-driven approach, a
state plan may include, for example, measures implemented consistent
with a utility integrated resource plan, including both measures that
directly apply to affected EGUs (e.g., repowering or retirement of one
or more EGUs) as well as RE and demand-side EE measures that avoid EGU
CO2 emissions.\273\ Under a state-driven approach, the
measures in a state plan would include emission standards for affected
EGUs, as well as requirements that apply to entities other than
affected EGUs, for example, renewable portfolio standards (RPS) or end-
use energy efficiency resource standards (EERS), both of which often
apply to electric distribution utilities.\274\
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\273\ In the case of a utility-driven portfolio approach, the
vertically integrated electric utility implementing portfolio
measures is also the owner and operator of affected EGUs.
\274\ A state-driven portfolio approach is more likely in states
that have instituted electricity sector restructuring, where
electric utilities have typically been required by states to divest
electric generating assets.
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c. Obligations on Affected EGUs
The EPA is proposing to authorize state plans to adopt the
portfolio approach and is proposing to interpret the CAA as allowing
that approach, as described in more detail below. CAA section 111(d)(1)
would certainly allow state plans to require the affected EGUs to be
the sole entities legally responsible for achieving the emission
performance level. The EPA is also soliciting comment on whether it can
reasonably interpret CAA section 111(d)(1) to allow states to adopt
plans that require EGUs and other entities to be legally responsible
for actions required under the plan that will, in aggregate, achieve
the emission performance level.
We note that some existing state programs, such as RGGI in the
northeastern states, do impose the ultimate responsibility on fossil
fuel-fired EGUs to achieve the required emission reductions, but are
also designed to work either concurrently, or in an integrated fashion,
with RE and demand-side EE programs that reduce the cost of meeting
those emission limitations. These existing programs offer a possible
precedent for another type of CAA section 111(d) state plan. Such a
plan approach could rely on CO2 emission standards
enforceable against affected EGUs--whether in the form of
[[Page 34902]]
emission rate or mass limits--to ensure achievement of the required
emission performance level, but also include enforceable or
complementary RE and demand-side EE measures that lower cost and
otherwise facilitate EGU emission reductions. Depending on the type of
plan, these RE and demand-side EE measures could either be enforceable
components of the plan (that is, the states could require affected EGUs
or other affected entities to invest in RE or in demand-side EE
programs) or be complementary to the plan. In this manner, RE and
demand-side EE measures could be a major component of a state's overall
strategy for reducing EGU CO2 emissions at a reasonable
cost.
It should be noted that state plan approaches that impose legal
responsibility on the affected EGUs to achieve the full level of
required emission performance could incorporate RE and demand-side EE
measures regardless of whether the emission standards that those plans
apply to the affected EGUs take the form of an emission rate or a mass
limit. Plans with rate-based emission limits could incorporate
enforceable RE and demand-side EE measures by adjusting an EGU's
CO2 emission rate when demonstrating compliance through
either an administrative adjustment by the state or use of a tradable
credit approach. (These actions would need to be enforceable components
of a state plan to facilitate EGU compliance with emission rate limits
and ensure that actions are properly quantified, monitored, and
verified.) A state plan that imposes a mass limit on affected EGUs that
is sufficiently stringent to achieve the emission performance level
would not need to include RE or demand-side EE measures as an
enforceable component of the plan to assure the achievement of that
performance level. The mass limit itself would suffice. However, the
state may wish to implement RE and demand-side EE measures as a
complement to the plan to support achievement of the mass limit at
lesser cost.
d. Federal Enforceability
Another concern expressed by some stakeholders is that including RE
and demand-side EE measures in state plans would render those measures
federally enforceable and thereby extend federal presence into areas
that, to date, largely have been the exclusive preserve of the state
and, in particular, state public utility commissions and the electric
utility companies they regulate. These stakeholders suggest that states
could rely on RE and demand-side EE programs as complementary measures
to reduce costs for, and otherwise facilitate, EGU emission limits
without including those measures in the CAA section 111(d) state plan.
Under this suggested approach, the EGU emission limits would be
federally enforceable, but RE and demand-side EE measures would serve
as complementary measures and would not be enforceable under federal
law; instead, they would remain enforceable under state law. According
to stakeholders, those types of state programs, particularly because
they are well-established, can be expected to achieve their intended
results. Thus, they suggest that the states could conclude that those
RE and demand-side EE measures would be beneficial in assuring the
achievement of the required emission performance level by the affected
EGUs specified in the CAA section 111(d) state plan, even without
including those measures in the plan.
e. Plans With State Commitments
As another vehicle for approving CAA section 111(d) plans for
states that wish to rely on state RE and demand-side EE programs but do
not wish to include those programs in their state plans, the EPA
requests comment on what we refer to as a ``state commitment
approach.'' This approach differs from the proposed portfolio approach,
described above, in one major way: Under the state commitment approach,
the state requirements for entities other than affected EGUs would not
be components of the state plan and therefore would not be federally
enforceable. Instead, the state plan would include an enforceable
commitment by the state itself to implement state-enforceable (but not
federally enforceable) measures that would achieve a specified portion
of the required emission performance level on behalf of affected EGUs.
The agency requests comment on the appropriateness of this approach.
The agency also requests comment on the policy ramifications of the
following: Under this approach, the state programs upon which the state
bases its commitment may, in turn, rely on compliance by third parties,
and if those state programs fail to achieve the expected emission
reductions, the state could be subject to challenges--including by
citizen groups--for violating CAA requirements and, as a result, could
be held liable for CAA penalties.
We also solicit comment on a variation of this state commitment
plan approach that is also designed to address stakeholder concerns,
noted above, about imposing sole legal responsibility on affected EGUs
for achieving the emission performance level. With this variation, the
state plan would in effect shift a portion of that responsibility to
the state, in the following manner: The state plan would impose the
full responsibility for achieving the emission performance level on the
affected EGUs, but the state would credit the EGUs with the amount of
emission reductions expected to be achieved from, for example, RE or
demand-side EE measures. The state would then assume responsibility for
that credited amount of emission reductions in the same manner as the
state commitment plan approach discussed above. We solicit comment on
whether, if the EPA were to conclude that CAA section 111(d) requires
state plans to include standards of performance applicable to affected
EGUs that achieve the emission performance level, this type of state
plan would meet that requirement while also assuring those EGUs an
important measure of support.
f. Legal Issues
The EPA is proposing to interpret the relevant provisions in CAA
section 111 to authorize state plans that achieve emissions reductions
from affected EGUs by means of the portfolio approach. CAA section
111(d)(1) requires each state to submit a plan that ``(A) establishes
standards of performance for any existing source [for certain air
pollutants] . . . and (B) provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(1)
defines a ``standard of performance'' as ``a standard for emissions of
air pollutants which reflects the degree of emission limitation
achievable through the application of the best system of emission
reduction . . . adequately demonstrated.''
These provisions make clear that emission limits that are
enforceable against affected EGUs appropriately belong in state plans
because they clearly are ``standards of performance.'' However, the
terms of CAA section 111(d)(1) do not explicitly address whether, in
addition to emission limits on affected EGUs, state plans may include
other measures for achieving the emission performance level. Nor do
they address whether entities other than affected EGUs may be subject
to requirements that contribute to reducing EGU emissions. Under the
U.S. Supreme Court's 1984 decision in Chevron U.S.A. Inc. v. NRDC,
where the statute leaves a gap, the agency has discretion to fashion an
interpretation
[[Page 34903]]
that is a reasonable construction of the statute.\275\
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\275\ Chevron U.S.A., Inc. v. NRDC, 467 U.S. 837, 842-44 (1984).
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The EPA is proposing to interpret the phrases ``standards of
performance for any existing source'' and ``the implementation and
enforcement of such standards of performance'' to encompass and allow
the various components of the portfolio approach. To the extent that a
portfolio approach contains measures that are not standards of
performance or do not implement or enforce such standards, the EPA is
proposing to interpret CAA section 111 as allowing state CAA section
111(d) plans to include measures that are neither standards of
performance nor measures that implement or enforce those standards,
provided that the measures reduce CO2 emissions from
affected sources. These measures would also be federally enforceable if
included in an approved plan.
The EPA's proposed interpretation is based, in part, on CAA section
111(d)'s requirement that states set performance standards ``for''
affected sources. Although ``for'' could be read as meaning that the
standards must apply to affected sources, ``for'' is also reasonably
interpreted to have a more capacious meaning: Standards (such as EE and
RE standards) are reasonably considered to be ``for'' affected sources
if they would have an effect on affected sources by, for example,
causing reductions in affected EGUs' CO2 emissions by
decreasing the amount of generation needed from affected EGUs. Under
this interpretation, and depending on the specific provisions in the
state plan, renewable energy and demand-side energy efficiency
requirements would be ``for'' fossil fuel-fired EGUs where such
standards result in reduced CO2 emissions from fossil fuel-
fired EGUs, even if the standards do not apply directly to fossil fuel-
fired EGUs.
The EPA also requests comment on another approach: Whether
``standards of performance for [affected sources]'' is reasonably read
to include the emission performance level (i.e., the state goal) on
grounds that the level is ``a standard for emissions'' because it is in
the nature of a requirement that concerns emissions and it is ``for''
the affected sources because it helps determine their obligations under
the plan.
Moreover, where the specific measures in the portfolio approach are
not themselves a ``standard of performance,'' state plans may include
measures that implement or enforce a standard of performance. For
example, if the state's plan achieves the emission performance level
through rate-based emission limits applicable to the affected sources,
coupled with a crediting mechanism for RE and demand-side EE measures,
we propose that RE and demand-side EE measures may be included in the
plan as ``implement[ing]'' measures because they facilitate the
sources' compliance with their standards of performance. We solicit
comment on the extent to which measures such as RE and demand-side EE
may be considered ``implement[ing]'' measures in state plans if they
are not directly tied to emission reductions that affected sources are
required to make through emission limits, and if they are requirements
on entities other than the affected sources. In addition, the EPA
proposes to interpret CAA section 111(d)(1) to allow state plans to
include components of the portfolio approach that are measures that
would reduce emissions from affected sources, even if those measures
are neither ``standards of performance for existing sources'' nor
measures ``for the implementation and enforcement of such standards of
performance.'' There is no specific language in CAA section 111(d) or
elsewhere in the Act that prohibits states from including measures
other than performance standards and implementation and enforcement
measures, provided that they reduce emissions from affected EGUs.
This interpretation is consistent with the principle of cooperative
federalism, which is one of the foundational principles of the Clean
Air Act and which supports providing flexibility to states to meet
environmental goals (provided minimum CAA statutory requirements are
met). This general principle, especially when combined with the
statutory directive that CAA section 111(d) regulations shall establish
procedures ``similar to that provided by section 110,'' supports an
interpretation of CAA section 111(d) that allows states sufficient
flexibility in meeting the state goal set under CAA section 111(d) to
include in their CAA section 111(d) plans other measures (i.e.,
measures that are neither performance standards nor measures that
enforce or implement performance standards). The EPA solicits comment
on all aspects of its proposed interpretation that states have this
flexibility in selecting measures for their state plans under CAA
section 111(d).
An alternative interpretation of CAA section 111(d)(1) would
suggest that the responsibility to achieve the state's required
emission performance level must be assigned solely to affected EGUs. As
described elsewhere in this preamble, there are a number of state-level
CO2 programs that take this approach while still taking
advantage of low-cost reductions from RE and demand-side EE through the
use of complementary measures. This alternative interpretation would be
based on, for example: A determination that CAA section 111(d)(1) must
be read as precluding a state plan from including measures that are
neither standards of performance nor measures for the implementation or
enforcement of such standards; an interpretation that the state's
obligation to set performance standards ``for'' existing sources means
that the standards must apply to affected EGUs and not to other
entities; and an interpretation that measures ``for the implementation
and enforcement of such performance standards'' do not include measures
that are not intended or designed to assist affected EGUs in meeting
the performance standards. The EPA requests comment on whether it must
adopt this alternative interpretation. If so, the EPA also takes
comment on whether there is a way, nonetheless, to allow states to rely
on the portfolio approach to some extent and/or for some period of
time.
We request comment on all of the interpretations discussed in this
section generally, and on all legal issues under CAA section 111(d)(1)
with respect to what measures can be included in a state plan and what
entities must be legally responsible for meeting those measures.
g. Ongoing Applicability of CAA Section 111(d) State Plan
The EPA is proposing that an existing source that becomes subject
to requirements under CAA section 111(d) will continue to be subject to
those requirements even after it undertakes a modification or
reconstruction. Under this interpretation, a modified or reconstructed
source would be subject to both (1) the CAA section 111(d) requirements
that it had previously been subject to and (2) the modified source or
reconstructed source standard being promulgated under CAA section
111(b) simultaneously with this rulemaking. It should be noted that
this proposal applies to any existing source subject to any CAA section
111(d) plan, and not only existing sources subject to the CAA section
111(d) plans promulgated under this rulemaking.
As noted above, a ``new source'' is defined under CAA section
111(a)(2) as ``any stationary source, the construction or modification
of which is commenced after,'' in general, a proposed or final CAA
section 111(b) rule becomes applicable to that source; and under
[[Page 34904]]
section 111(a)(6), an ``existing source'' is defined as ``any
stationary source other than a new source.'' Under these definitions,
an ``existing source'' that commences construction of a modification or
reconstruction after the EPA has proposed or finalized a CAA section
111(b) standard of performance applicable to it, becomes a ``new
source.'' However, CAA section 111(d) is silent on whether requirements
imposed under a CAA section 111(d) plan continue for a source that
ceases to be an existing source because it modifies or reconstructs.
Specifically, CAA section 111(d)(1) provides that ``each State shall
submit to the Administrator a state plan which (A) ``establishes
standards of performance for any existing source'' but does not say
whether, once the EPA has approved a state plan that establishes a
standard of performance for a given source, that standard is lifted if
the source ceases to be an existing source. Similarly, no other
provisions of CAA section 111 address whether the imposition of a CAA
section 111(b) standard on a modified or reconstructed source ends the
source's obligation to meet any applicable CAA section 111(d)
requirements.
Because CAA section 111(d) does not address whether an existing
source that is subject to a CAA section 111(d) program remains subject
to that program even after it modifies or reconstructs, the EPA has
authority to provide a reasonable interpretation, under the Supreme
Court's decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-844
(1984). The EPA's interpretation is that under these circumstances, the
source remains subject to the CAA section 111(d) plan, for two reasons.
The first is to assure the integrity of the CAA section 111(d) plan.
The EPA believes that many states will develop integrated plans that
include all of their EGUs, such as rate- or mass-based trading
programs. Uncertainty about whether units would remain in the program
could be very disruptive to the operation of the program. The second
reason is to avoid creating incentives for sources to seek to avoid
their obligations under a CAA section 111(d) plan by undertaking
modifications. The EPA is concerned that owners or operators of units
might have incentives to modify purely because of potential
discrepancies in the stringency of the two programs, which would
undermine the emission reduction goals of CAA section 111(d).
The EPA invites comments on this interpretation of CAA section
111(d)(1), including whether this interpretation is supported by the
statutory text and whether this interpretation is sensible policy and
will further the goals of the statute. It should be noted that this
interpretation is severable from the rest of this rulemaking, so that
if the EPA revises this interpretation in the final rule or if the EPA
adopts this interpretation in the final rule but it is invalidated by a
Court, there would be no effect on the rest of this rulemaking.
2. Timing for Implementation and Achievement of Goals
This section describes proposed state plan requirements related to
the timing of achieving emission performance goals, including
performance demonstrations, performance periods, and interim progress
milestones.
As previously discussed, the goals are derived from application of
four ``building blocks.'' The EPA has based the application of some of
these measures to reduce CO2 emissions, particularly blocks
3 (expansion of cleaner generating capacity) and 4 (increasing demand-
side energy efficiency), on forward-looking, longer-term assumptions.
For example, the EPA expects technologies to reduce carbon emissions to
more fully develop over time and acknowledges the cumulative effects of
implementation of EE programs and addition of RE generating capacity
over time. Therefore, the EPA is not proposing to require each state to
meet its full, final goal immediately, but rather to meet it by 2030.
The EPA realizes, however, that states can achieve emission reductions
from those and other measures in the short-term. Therefore, the EPA is
proposing that states begin meeting interim goals, beginning in 2020.
The EPA also believes that timing flexibility in implementing measures
provides significant benefits that allow states to develop plans that
will help states achieve a number of goals, including: Reducing cost,
addressing reliability concerns, and addressing concerns about stranded
assets. Therefore, the EPA is also proposing to allow states
flexibility to define the trajectory of emission performance between
2020 and 2029, as long as the interim emission performance level is met
on a 10-year average or cumulative basis and the 2030 emission
performance level is achieved.
Section VIII.B.1.a of this preamble provides an overview of the
proposals for state plan performance demonstrations and timing of
emission reductions. Subsequent subsections include proposals for the
start date for the interim goal performance period, the duration of the
performance periods for the final and interim goals, interim progress
milestone requirements, consequences if actual emission performance
does not meet the state goal, and out-year requirements for states to
maintain CO2 emission performance levels over time
consistent with the final goal. In Section VIII.B.2.f of this preamble,
the agency also requests comment on alternative requirements aimed at
continued emission performance improvement after 2029. In Section
VIII.B.2.g of this preamble, the EPA proposes flexibility for states to
change from mass-based to rate-based goals in different performance
periods and, in Section VIII.B.2.h, we solicit comment on planning
requirements that match the option of alternative, less stringent state
goals.
a. Performance Demonstrations and Timing of Emission Reductions
As described previously, the agency is proposing final state-
specific goals (specified in Table 8) that represent emission rates to
be achieved by 2030, as well as interim goals, to be achieved on
average over the 10-year period from 2020-2029. The agency is also
proposing that emission performance levels consistent with the final
state-specific goals be maintained after 2030.
This relatively long planning and implementation period provides
states with substantial flexibility regarding methods and timing of
achieving emission reductions. States may wish to make adjustments to
their implementation approaches along the way, or as conditions change
may need to make adjustments to ensure that their plans achieve the
goals as intended. As a result, the agency envisions that the EPA,
states, and affected entities will have an ongoing relationship in the
course of implementing this program.
The EPA proposes that a state plan must demonstrate projected
achievement of the emission performance levels in the plan, and these
emission performance levels must be equivalent to or better than the
interim and final goals established by the EPA. Specifically, the state
plan must demonstrate that the projected emission performance of
affected EGUs in the state will be equivalent to or better than the
applicable interim goal during the 2020-2029 period, and equivalent to
or better than the applicable final goal during the year 2030. The
state plan must identify requirements that continue to apply after 2030
and are likely to maintain continued emission performance by affected
EGUs that meets the final goal; however, quantitative projections of
emission performance by affected EGUs
[[Page 34905]]
beyond 2030 would not be required by this rule under the proposed
approach. Instead, the EPA proposes that the state plan would be
considered to provide for maintenance of emission performance
consistent with the final goal if the plan measures used to demonstrate
achievement of the final goal by 2030 will continue in force and not
sunset.
In addition to demonstrating that projected plan performance will
meet the interim and final state goals, the EPA proposes that state
plans must contain requirements for tracking actual plan performance
during implementation. For plans that do not include enforceable
requirements for affected EGUs that ensure achievement of the full
level of required emission performance and interim progress, the state
plans would be required to include periodic program implementation
milestones and emission performance checks, and include corrective
measures to be implemented if mid-course corrections are necessary. The
state plan would provide for continued tracking of emission performance
after 2030, and for corrective measures if the emission performance of
affected EGUs in the state did not continue to meet the 2030 final goal
during any three-year performance period.
The rationale for this approach is that it would ensure that states
design their plans in a way that considers both the interim and final
goals. If only the interim goal were considered, a state plan might not
be sufficient to achieve the final goal.\276\
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\276\ The 2020-2029 interim goal is expressed as a 10-year
average emission rate to provide states with flexibility in
designing their plans. Due to the potential for continued end-use
energy efficiency improvements, the 2029 four-building-block BSER-
based level is a more stringent level than the 2020-2029 average
four-building-block BSER-based level. The purpose of the final goal
is to ensure that each state ultimately achieves the emission
performance level for affected EGUs that is achievable by 2029.
Without the final goal, it is possible that a state could achieve
the 2020-2029 interim goal but not achieve the 2030 final goal.
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The agency requests comment on a second option in which, in
addition to submitting a plan demonstrating emission performance
through 2030, states would be required to make a second submittal in
2025 showing whether their plan measures would maintain the final-goal
level of emission performance over time (as further described below).
If not, the state submittal would be required to strengthen or add to
measures in the state plan to the extent necessary to maintain that
level of performance over time.
The EPA also requests comment on whether 2025, or an earlier or
later year, would be the optimal year for a second plan submittal under
the second option.
b. Start Date for Performance Period for Interim Goal
A performance period is a period for which the state plan must
demonstrate that the required emission performance level will be met.
The EPA proposes a start date of January 1, 2020, for the interim goal
plan performance period.\277\ This date would be the beginning of the
10-year period for which a state must demonstrate that the projected
emission performance level of affected EGUs in the state, on average,
will be equivalent to or better than the applicable interim goal. The
agency generally requests comment on the appropriate start date and
rationale.
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\277\ The start date for a plan performance period must match
the start date of the corresponding state emission performance goal.
If a start date other than January 2020 were selected, the EPA would
recompute the state goals consistent with the selected start date.
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In considering the start date, it is relevant to consider the due
dates for state plan submittals and the amount of time available for
program implementation by the start date. January 2020 is 3.5 years
from the proposed June 2016 deadline for initial plan submittals, 2.5
years from the proposed June 2017 extended deadline for complete plans
from states not participating in a multi-state plan, and 1.5 years from
the proposed June 2018 extended deadline for complete plans from states
participating in a multi-state plan. The EPA suggests that affected
entities may have greater lead time for compliance than might be
implied by the plan submittal dates referenced above. Affected entities
will have knowledge of state requirements as they are adopted, and the
state must adopt rules and requirements in advance of submitting its
complete plan to the EPA. Also, as explained in detail in subsection c,
states may choose a different emission performance improvement
trajectory from that which the EPA assumes for purposes of calculating
state goals, achieving lesser levels of performance in early years and
more in later years, provided, of course, that the interim 10-year
average requirement is met.
The EPA proposes that a 2020 start date for the interim goal plan
performance period is achievable in light of the following additional
considerations. First, existing state programs will play a role in
helping to achieve this rule's proposed emission performance levels.
Second, in advance of this proposal, many states already were
contemplating design of strategies that would achieve CO2
emission reductions equivalent to those that could be required by CAA
section 111(d) emission guidelines. Third, for inclusion in the
building blocks, the EPA considered only those emission abatement
measures that are technically feasible and broadly applicable, and can
provide reductions in CO2 emissions from affected EGUs at
reasonable cost.
For example, the EPA expects that many EGUs will meet their
requirements in part by implementing heat rate improvements, and those
actions may be undertaken promptly. The plant operations and
maintenance (O&M) and engineering solutions used to improve heat rates
at existing EGUs have long been commercially available and have been
implemented at EGUs for many years. Further, the relatively modest
capital costs (average $100/kW) and significant fuel savings associated
with a suite of heat rate improvement (HRI) methods result in this
measure being a low-cost approach to reducing CO2 emissions
from existing EGUs. HRI ``best practices'' (e.g., installation of
modern control systems, operator training, smart soot blowing) are the
least-cost HRI methods and can be applied quickly, without lengthy EGU
outages. The somewhat more costly HRI ``upgrades'' (e.g., steam turbine
upgrade, boiler draft fan/driver upgrade) may require modest EGU
outages to implement, but have also been applied on numerous EGUs to
improve or maintain performance. Drawing on the power sector's
extensive experience with HRI methods, and the many existing supply
chains already supporting these methods, the EPA expects that it would
be feasible to implement HRI projects (i.e., building block 1) by 2020.
Dispatch changes, which are largely driven by the variable cost of
operating a given EGU, occur on an hourly basis in the power sector.
The average availability factor for NGCCs in the U.S. generally exceeds
85 percent, and can exceed 90 percent for selected groups.\278\ In
addition, the existing natural gas pipeline and electricity
transmission networks are already connected to every existing NGCC
facility, and can support aggregate operation of the NGCC fleet at 70
percent (or above) at the state level, or can be reasonably expected to
do so in the time frame for compliance with this rule. Therefore,
building block 2, which represents shifting of generation from steam
fossil EGUs to existing NGCCs, is a viable method for providing
CO2
[[Page 34906]]
emission reductions at existing EGUs by the 2020 compliance start date.
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\278\ Source: NERC, 2008-2012 Generating Unit Statistical
Brochure.
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Building Block 3 is based on shifting generation from affected
fossil units to new renewable energy generating capacity, which is
added over time, and new or preserved nuclear capacity, all of which is
expected to be in place by 2020 (see the GHG Abatement Measures TSD for
more information).
Finally, there is considerable experience with the states and the
power sector in designing and implementing demand-side energy
efficiency improvement strategies and programs. It is also well
accepted that such improvements can achieve reductions in
CO2 emissions from existing EGUs at a reasonable cost.
Building block 4 represents a feasible pathway for reducing utilization
of carbon-emitting EGUs by implementing improvements in demand-side
energy efficiency. This building block is based on a ``best practices''
scenario where all states achieve a level of performance--matching a
level achieved or committed to by twelve leading states--of 1.5 percent
annual incremental electricity savings as a percentage of retail sales.
For the best practices scenario, all states achieve this level of
performance no later than 2025, with leading states reaching this level
sooner. Each state's current level of performance is taken into
account, with states achieving lower levels of performance being
allowed more time to reach the best practice level.
c. Duration of Performance Periods for Final and Interim Goals
The EPA recognizes that a state's circumstances and choice of
emission reduction strategies may affect the timing of CO2
emission performance improvement within a multi-year planning period.
States can be expected to select various combinations of measures and
those measures may vary in the time needed to reach full
implementation. The agency recognizes that certain emission reduction
measures and programs (e.g., heat rate improvements) are generally
easier to implement in the near term, while others (e.g., renewable
portfolio standards, demand-side energy efficiency programs) may
require several years to implement because of the time necessary to
establish the proper infrastructure if a state does not already have
such programs in place. Though some states have already implemented
such programs that are achieving results, other states may have to
establish them for the first time. New single and multi-state programs,
as well as existing single and multi-state programs that are adding or
revising measures, may need time for implementation to achieve the
required level of emission performance.
As described in Section VII of the preamble, the EPA is proposing
state-specific CO2 emission performance goals in a multi-
year format to provide states with flexibility for the timing of
programs and measures that improve EGU emission performance, while
ensuring an overall level of performance consistent with application of
the BSER. Specifically, the agency is proposing the state-specific
goals (shown in Table 8) which represent emission rates to be achieved
by 2030 (final goal) and emission rates to be achieved on average over
the 2020-2029 period (the interim goal).
The EPA proposes the following as the preferred option for the
final and interim goal performance periods. As further explained below,
this option reflects three main objectives: (1) Provide states with
timing flexibility during the interim goal period to accommodate
differences in state adoption processes and types of state programs,
(2) ensure that state plans are designed to achieve the final goal no
later than 2030, and (3) provide flexibility for year-to-year variation
in actual emission performance that may occur as the electricity system
responds to economic fluctuations.
Interim goal--Projected plan performance demonstration: To be
approvable, a state plan must demonstrate that the emission performance
of affected EGUs will meet the interim emission performance level on
average over the 2020-2029 period.
Interim goal--Actual plan performance check: In 2030, the emission
performance of affected EGUs during the period 2020-2029 must be
compared against the interim goal. (In addition, as described
separately below, interim emission performance checks will occur during
this 10-year period.)
Final goal--Projected plan performance demonstration: To be
approvable, a state plan must demonstrate that the emission performance
of affected EGUs will meet the final emission performance level no
later than 2030, on a single-year basis.
Final goal--Actual plan performance check: Starting at the end of
2032, emission performance of affected EGUs must be compared against
the final goal on a three-year rolling average basis (i.e., 2030-32,
2031-33, 2032-2034, etc.).
This proposed approach provides a 10-year performance period for
the interim performance level. The 10-year period allows states
flexibility for timing of program implementation as the state ramps up
its programs to achieve the final performance level. Using the single
year 2030 as the projected year for achievement of the final goal
ensures that state plans are designed to achieve the final goal no
later than 2030; providing a multi-year time frame for projected plan
performance would inappropriately delay the requirement for a final-
goal level of performance that the EPA's analysis shows is achievable
at the end of the 10-year interim ramp-up period. Using 2030 also
avoids overlap with the interim goal performance period. The rolling
three-year performance periods for measuring actual plan performance
against the final goal performance level are proposed in light of year-
to-year variability in economic and other factors, such as weather,
that influence power system operation and affect EGU CO2
emissions. The choice of 2030-2032 avoids overlap with the 2020-2029
interim goal performance period.
For a rate-based plan, 2020-2029 emission performance is an average
CO2 emission rate for affected EGUs representing cumulative
CO2 emissions for affected EGUs over the course of the 10-
year performance period divided by cumulative MWh energy output \279\
from affected EGUs over the 10-year performance period, with rate
adjustments for qualifying measures, such as end-use energy efficiency
and renewable energy measures, as described in Section VIII.F.3. For a
mass-based plan, 2020-2029 emission performance is total tons of
CO2 emitted by affected EGUs over the 10-year performance
period.
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\279\ For EGUs that produce both electric energy output and
other useful energy output, there would also be a credit for non-
electric output, expressed in MWh.
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The agency invites comment on this and other approaches to
specifying performance periods for state plans.
d. Program Implementation Milestones and Tracking of Emission
Performance
The EPA recognizes the importance of ensuring that, during the
proposed 10-year performance period (2020-2029) for the interim goal, a
state is making steady progress toward achieving the required level of
emission performance. The EPA is proposing that certain types of state
plans be required to have program implementation milestones to ensure
interim progress, as well as periodic checks on overall emission
performance leading to corrective measures if necessary.
Some types of plans are ``self-correcting'' in that they inherently
[[Page 34907]]
would assure interim performance and full achievement of the state
plan's required level of emission performance through requirements that
are enforceable against affected EGUs. One example is a state plan with
a rate-based emission performance level that requires affected EGUs
collectively to meet an emission rate consistent with the state's
required emission performance level, and allows EGUs to comply through
an emission rate averaging system. Another example is a plan that
includes measures or actions (e.g., emission limits that apply to
affected EGUs and ensure full plan performance) that take effect
automatically if the plan's required emission performance level is not
met, in accordance with a specified milestone. The EPA requests comment
on whether there are other types of state plans that should be
considered ``self-correcting.''
The EPA proposes that self-correcting plans need not contain
interim milestones consisting of program implementation steps, because
these state plans inherently require both interim progress and
achievement of the full level of required emission performance in a
manner that is federally enforceable against affected EGUs. Annual
reporting of emission performance by the state, however, is required
for all types of plans.
For plans that are not self-correcting, the EPA proposes that the
state plan must identify periodic program implementation milestones
(e.g., start of an end-use energy efficiency program, retirement of an
affected EGU, or increase in portfolio requirements under a renewable
portfolio standard) that are appropriate to the programs and measures
included in the plan. If, during plan implementation, a state were to
miss program implementation milestones in its plan, it would need to
report the delay to the EPA, explain the cause, and describe the steps
the state will take to accelerate subsequent implementation to achieve
the planned improvements in emission performance. Depending on the
severity of delay and the explanation, the EPA could ultimately
evaluate actions under CAA authorities to ensure timely program
implementation.
In addition, we propose that the state and the EPA would track
state plan emission performance on an ongoing basis, with states
reporting performance data to the EPA annually by July 1. During the
interim performance period, beginning in 2022, the state would be
required each year to include a comparison of emission performance
achieved to performance projected in the state plan. Each comparison
would cover the preceding two-year period. The EPA may also approve
regular, periodic emission comparison checks with a different frequency
or comparison period to reflect the design of a state's programs (e.g.,
compliance periods for EGUs under an emission limit).
A report and corrective measures would be required if an interim
emission check showed that actual emission performance of affected
entities was not within 10 percent of the performance projected in the
state plan (i.e., for a rate-based plan, if the average emission rate
of affected EGUs were 10 percent higher than plan projections, or for a
mass-based plan, if collective emissions of affected EGUs were 10
percent higher than plan projections). In that event, the state would
be required in its submission to explain reasons for the deviation
(e.g., energy efficiency program not working as effectively as
expected, prolonged extreme weather that had been unanticipated in
electricity demand projections) and specify the corrective measures
that will be taken to ensure that the required level of emission
performance in the plan will be met. The state also would be required
to implement those corrective measures as expeditiously as practical.
The agency proposes that states be given a choice regarding when to
adopt into regulation the corrective measures that the state plan
identifies for implementation in the event that state plan performance
is deficient. First, the state could adopt corrective measures into
regulation prior to plan submittal in a manner that enables the state
to implement the measures administratively, without further legislation
or rulemaking, if a performance deficiency occurs during plan
implementation. This would expedite implementation of corrective
measures once a deficiency is discovered. Second, the state could elect
to wait to adopt into regulation the corrective measures identified in
the plan until after a plan performance deficiency is discovered. The
EPA proposes this choice in recognition of the fact that it may be
challenging for states to fully adopt corrective measures in advance to
address the possibility that their plan will not perform as projected.
However, if a state makes the latter choice, the EPA proposes that the
state must report the reasons for deficient performance and must
implement corrective measures if actual emission performance was
inferior to projected performance by eight percent or more (rather than
10 percent or more). The reason for the lower percentage trigger is to
identify a gradually developing deficiency in plan performance earlier
in time. Legislative and/or regulatory action to adopt corrective
measures after a deficiency is discovered will take significant time.
State processes to activate corrective measures should be triggered
earlier if corrective measures are not adopted in regulation and ready
to implement.
The EPA alternatively requests comment on whether states should be
required to create legal authority and/or adopt regulations providing
for corrective measures in developing the state plan. The agency
requests comment generally on the conditions that should trigger
corrective measure requirements. The agency also solicits comment on
whether actual emission performance inferior to projected performance
by ten percent (for plans with corrective measures adopted into
regulation prior to complete plan submittal) is the appropriate trigger
for requiring a state to report the reasons for deficient performance
and to implement corrective measures. We are also soliciting comment on
the range of five percent to fifteen percent. For plans without
corrective measures adopted into regulation prior to complete plan
submittal, the agency solicits comment on whether the proposed eight
percent emission performance deviation trigger is appropriate. We also
solicit comment on the range of five percent to ten percent.
The EPA proposes that the state will be required to compare actual
emission performance achieved during the entire 10-year interim
performance period (i.e., 2020-2029) against the interim goal. As noted
above, beginning after 2032, the EPA proposes that the state be
required to compare actual emission performance achieved against the
final goal on a rolling three-year average basis (e.g., 2030-32, 2031-
33, etc.). The EPA also requests comment on the milestone approach and
emission performance checks outlined above in the context of the
alternative 5-year performance period and the planning approach for
alternative state goals, which is described below.
e. Consequences if Actual Emission Performance Does Not Meet State Goal
There are scenarios under which an approved state plan might fail
to achieve a level of emission performance by affected EGUs that meets
the state goal. Under some types of plans, a possible scenario is that
despite successful plan implementation, emissions under the plan turn
out to be higher than projected at the time of plan
[[Page 34908]]
approval because actual economic conditions vary from economic
assumptions used when projecting emission performance. State officials
have raised the possibility that achieved emission performance might
not meet projected performance if, for example, planned retirements of
EGUs were postponed because severe weather produced greater-than-
expected electricity generation needs. In addition, emissions could
theoretically exceed projections because affected entities under a
state plan did not fulfill their responsibilities, or because the state
did not fulfill its responsibilities.
The EPA believes that the emission guidelines should specify the
consequences in the event that actual emission performance under a
state plan does not meet the applicable interim goal in 2020-2029, or
does not meet the applicable final goal in 2030-2032 or later, because
CAA section 111(d) is not specific on this point. The agency requests
comment on how the consequences should vary depending on the reasons
for a deficiency in performance.
Specifically, the agency requests comment on whether consequences
should include the triggering of corrective measures in the state plan,
or plan revisions to adjust requirements or add new measures. The
agency also requests comment on whether corrective measures, in
addition to ensuring future achievement of the state goal, should be
required to achieve additional emission reductions to offset any
emission performance deficiency that occurred during a performance
period for the interim or final goal. This concept has been applied,
for example, in the Acid Rain Program under Title IV of the CAA; a
source that has sulfur dioxide emissions exceeding the emission
allowances that it holds at the end of the period for demonstrating
compliance is required subsequently to obtain additional emission
reductions to offset its excess emissions.\280\ The agency also
requests comment on the process for invoking requirements for
implementation of corrective measures in response to a state plan
performance deficiency.
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\280\ CAA section 411(b).
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The EPA further requests comment on whether the agency should
promulgate a mechanism under CAA section 111(d) similar to the SIP call
mechanism in CAA section 110. Under this approach, after the agency
makes a finding of the plan's failure to achieve the state goal during
a performance period, the EPA would require the state to cure the
deficiency with a new plan within a specified period of time (e.g., 18
months). If the state still lacked an approved plan by the end of that
time period, the EPA would have the authority to promulgate a federal
plan under CAA section 111(d)(2)(A).
f. Out-Year Requirements: Maintaining or Improving the Level of
Emission Performance Required by the Final Goal
The agency is determining state goals for affected EGU emission
performance based on application of the BSER during specified time
periods. This raises the question of whether affected EGU emission
performance should only be maintained--or instead should be further
improved--once the final goal is met in 2030. This involves questions
of goal-setting as well as questions about state planning. In this
section, the EPA proposes that a state must maintain the required level
of performance, and requests comment on the alternative of requiring
continued improvement.
The EPA believes that Congress either intended the emission
performance improvements required under CAA section 111(d) to be
permanent or, through silence, authorized the EPA to reasonably require
permanence. Other CAA section 111(d) emission guidelines set emission
limits to be met permanently. Therefore, the EPA is proposing that the
level of emission performance for affected EGUs represented by the
final goal should continue to be maintained in the years after 2030.
The EPA is proposing a mechanism for implementing this objective, and
is taking comment on an alternative option.
As noted above, the EPA proposes that the state plan must
demonstrate that plan measures are projected to achieve the final
emission performance level by 2030. In addition, the state plan must
identify requirements that continue to apply after 2030 and are likely
to maintain affected EGU emission performance meeting the final goal;
however, quantitative projections of emission performance beyond 2030
would not be required under the proposed option. Instead, the EPA
proposes that the state plan would be considered to provide for
maintenance of emission performance consistent with the final goal if
the plan measures used to demonstrate projected achievement of the
final goal by 2030 will continue in force and not sunset.\281\ After
implementation, the state would be required to compare actual plan
performance against the final goal on a rolling three-year average
basis starting in 2030, and to implement corrective measures if
necessary.
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\281\ This is straightforward for plans with EGU emission limits
that ensure the full level of performance required. For renewable
energy programs, the agency suggests that the state could continue
to require the renewable portfolio percentage level that was relied
upon to demonstrate projected achievement of the final goal
performance level in 2030. For plans that rely in part on end-use
energy efficiency programs and measures, the EPA requests comment on
what a state would need to require in its plan to show that
performance will be maintained after 2030. End-use energy efficiency
programs and measures often involve an annual energy savings
requirement or goal, and some types require additional monetary
expenditures each year to meet those savings requirements or goals.
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The EPA also requests comment on an alternative approach to a
state's pre-implementation demonstration that the final-goal level of
performance will be maintained after 2030. Under this alternative, the
state plan would be required to include projections demonstrating that
emission performance would continue to meet the final goal for up to 10
years beyond 2030. This approach could be implemented through a second
round of state plan analysis and submittals in 2025 to make the
demonstration and strengthen or add measures if necessary. The EPA
generally requests comment on appropriate requirements to maintain the
emission performance of affected EGUs in years after 2030.
The EPA also requests comment on whether we should establish BSER-
based state emission performance goals for affected EGUs that extend
further into the future (e.g., beyond the proposed planning period),
and if so, what those levels of improved performance should be. Under
this alternative, the EPA would apply its goal-setting methodology
based on application of the BSER in 2030 and beyond to a specified time
period and final date. The agency requests comment on the appropriate
time period(s) and final year for the EPA's calculation of state goals
that reflect application of the BSER under this approach.
The EPA notes that CAA section 111(b)(1)(B) calls for the EPA, at
least every eight years, to review and, if appropriate, revise federal
standards of performance for new sources. This requirement provides for
regular updating of performance standards as technical advances provide
technologies that are cleaner or less costly. The agency requests
comment on the implications of this concept, if any, for CAA section
111(d).
g. State Flexibility To Choose Mass-Based and Rate-Based Goals After
2029
The EPA proposes that states have flexibility to choose between a
rate-
[[Page 34909]]
based and mass-based performance level for each performance period. For
example, if a state plan used a mass-based performance level for the
2020-2029 period, the state plan may still use a rate-based performance
level for final goal performance periods, or vice versa.
A state that adopted a mass-based performance level for 2020-2029
would have two options for addressing any perceived need for emissions
flexibility in light of anticipated electricity demand growth after
2029. The state either could adopt a rate-based performance level
consistent with the final goal, or could adopt a mass-based performance
level based on a translation of the rate-based final goal to a mass-
based goal.
h. Planning Approach for Alternative State Goals
In Section VII, the EPA requests comment on alternative, five-year
state emission performance goals for affected EGUs shown in Table 9.
The alternative goals represent emission rates achievable on average
during the 2020-2024 period, as well as emission rates to be achieved
and maintained after 2024. These alternative goals are less stringent
than the proposed goals in Table 8.
To accompany the alternative goals, the EPA requests comment on
another approach for state plan performance periods. This approach
would require state plans to demonstrate that the required interim
emission performance level will be met on average by affected EGUs
during the five-year 2020-2024 interim period, and that the alternative
final goal be met no later than 2025. After plan implementation, actual
emission performance would be compared with the alternative final goal
on a three-year rolling average basis, starting with 2025-2027, in
light of year-to-year variability in economic and other factors, such
as weather, that influence power system operation and affect EGU
CO2 emissions.
In connection with the alternative state goals, for the years after
2027, the EPA requests comment on the same ``out-year'' issues and
concepts for maintaining or improving emission performance over time
that are described above in Section VIII.B.2.f. The EPA requests
comment on whether a state plan should provide for emission performance
after 2025 solely through post-implementation emission checks that do
not require a second plan submittal, or whether a state should also be
required to make a second submittal prior to 2025 to demonstrate that
its programs and measures are sufficient to maintain performance
meeting the final goal for at least 10 years. In addition, the agency
requests comment on the appropriate date for any second state plan
submittal designed to maintain emission performance after the 2025
performance level is achieved.
C. Criteria for Approving State Plans
The EPA is proposing to require the twelve plan components
discussed in Section VIII.D of this preamble. We will evaluate the
sufficiency of each plan based on the plan addressing those components
and on four general criteria for a state plan to be approvable. The EPA
proposes to use the combination of these twelve plan components and
four general criteria to determine whether a state's plan is
``satisfactory'' under CAA section 111(d)(2)(A). First, a state plan
must contain enforceable measures that reduce EGU CO2
emissions. Second, these enforceable measures must be projected to
achieve emission performance equivalent to or better than the
applicable state-specific CO2 goal on a timeline equivalent
to that in the emission guidelines.\282\ Third, EGU CO2
emission performance under the state plan must be quantifiable and
verifiable. Fourth, the state plan must include a process for state
reporting of plan implementation (at the level of the affected entity),
CO2 emission performance outcomes, and implementation of
corrective measures, if necessary. The EPA requests comments on all
aspects of these general criteria and the twelve specific plan
components described below.
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\282\ Flexibilities provided to states in meeting this general
approvability criterion are discussed below in Section VIII.C.2.,
emission performance.
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The agency also notes that a CAA section 111(d) state plan is not a
CAA section 110 state implementation plan (SIP). Although there are
similarities in the two programs, approvability criteria for CAA
section 111(d) plans need not be identical to approvability criteria
for SIPs.
1. Enforceable Measures
In developing its plan, a state must ensure that the plan is
enforceable and in conformance with the CAA. We are seeking comment on
the appropriateness of existing EPA guidance on enforceability in the
context of state plans under CAA section 111(d), considering the types
of affected entities that might be included in a state plan.\283\ This
guidance serves as the foundation for the types of emission limits that
the EPA has found can be enforced as a practical matter and sets forth
the general principle that a requirement that is enforceable as a
practical matter is one that is quantifiable, verifiable,
straightforward, and calculated over as short a term as reasonable.
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\283\ Enforceability guidance includes:(1) September 23, 1987
memorandum and accompanying implementing guidance, ``Review of State
Implementation Plans and Revisions for Enforceability and Legal
Sufficiency,'' (2) August 5, 2004 ``Guidance on SIP Credits for
Emission Reductions from Electric-Sector Energy Efficiency and
Renewable Energy Measures,'' and (3) July 2012 ``Roadmap for
Incorporating Energy Efficiency/Renewable Energy Policies and
Programs into State and Tribal Implementation Plans, Appendix F.''
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As discussed in section VIII.F.1, the EPA is seeking comment on
whether the agency should provide guidance on enforceability
considerations related to requirements in a state plan for entities
other than affected EGUs (and if so, which types of entities). Also, as
discussed in section VIII.F.4, the EPA intends to develop guidance for
evaluation, monitoring, and verification (EM&V) of renewable energy and
demand-side energy efficiency programs and measures incorporated in
state plans.
A state plan must include enforceable CO2 emission
limits (either rate-based or mass-based) that apply to affected EGUs.
As noted above, the EPA is proposing that a state plan may take a
portfolio approach, which would include enforceable CO2
emission limits that apply to affected EGUs as well as other
enforceable measures, such as RE and demand-side EE measures, that
avoid EGU CO2 emissions and are implemented by the state or
by another entity assigned responsibility by the state. As noted above,
we are proposing that state plans are not required to impose emission
limits on affected EGUs that in themselves fully achieve the emission
performance level. However, we are seeking comment on whether, for
state plans where emission limits applicable to affected EGUs alone
would not assure full achievement of the required level of emission
performance, the state plan must include additional measures that would
apply if any of the other portfolio of measures in the plan are not
fully implemented, or if they are, but the plan fails to achieve the
required level of emission performance.\284\
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\284\ This could include, for example, an expansion of the scope
or an increase in stringency of the current measures in the plan, a
second set of measures that avoid EGU CO2 emissions, or
emissions limits that apply to affected EGUs.
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The EPA recognizes that a portfolio approach may result in
enforceable state plan obligations accruing to a diverse range of
affected entities beyond affected EGUs, and that there may be
challenges to practically enforcing against some such entities in the
event of noncompliance. We request comment
[[Page 34910]]
on all aspects associated with enforceability of a state plan and how
to ensure compliance. We are also seeking comment on enforceability
considerations under different state plan approaches, which is
addressed below in VIII.F.1.
2. Emission Performance
The second criterion for approvability is that the projected
CO2 emission performance by affected EGUs (taking into
account the impacts of plan measures that are associated with reducing
utilization from affected EGUs) must be equivalent to, or better than,
the required CO2 emission performance level in the state
plan. State plans that are projected to achieve an average
CO2 emission rate (expressed in lb CO2/MWh) or
tonnage CO2 emission outcome by all affected EGUs equal to,
or lower than, the required level of CO2 emission
performance in the plan would meet this approvability criterion.
We are proposing that states may demonstrate such emission
performance by affected EGUs either on an individual state basis or
jointly on a multi-state basis.
All of the emission reduction measures included in the agency's
determination of the BSER reduce CO2 emissions from affected
EGUs. As a result, the EPA is not proposing that out-of-sector GHG
offsets could be applied to demonstrate CO2 emission
performance by affected EGUs in a state plan.
However, emission limits for affected EGUs that are included in
state plans could still include provisions that provide the ability to
use GHG offsets for compliance with the emission limits, provided those
emission limits would achieve the required level of emission
performance for affected EGUs. We note that inclusion of such
provisions would create a degree of uncertainty about the level of
emission performance that would be achieved by affected EGUs when
complying with the emission limit (as potentially would other
flexibility mechanisms included in an emission limit). As a result,
such emission limits would not be considered ``self-correcting'' as
discussed above at Section VIII.B.2.d.
All existing state emission budget trading programs addressing GHG
emissions include out-of-sector, project-based emission offsets, which
may be used to cover a portion of the compliance obligation of affected
sources. Other states may want to take a similar approach, for example,
to incentivize GHG emission reductions from land use and agricultural
waste management. How to address GHG offsets included in EGU emission
limits when projecting emission performance under a state plan is
addressed in the Projecting EGU CO2 Emission Performance in
State Plans TSD.
The ISO/RTO Council, an organization of electric grid operators,
has suggested that ISOs and RTOs could play a facilitative role in
developing and implementing region-wide, multi-state plans, or
coordinated individual state plans. Existing ISOs and RTOs could
provide a structure for achieving efficiencies by coordinating the
state plan approaches applied throughout a grid region. Just as the
ISO/RTO regions today share the benefits and costs of efficient EGU
dispatch across state boundaries, there are significant efficiencies
that could be captured by coordinating individual state plans or
implementing multi-state plans within a grid region. Under one variant
of this approach, states would implement a multi-state plan and jointly
demonstrate CO2 emission performance by affected EGUs across
the entire ISO/RTO footprint. States with borders that cross the
boundary of one or more ISO or RTO footprints would need to include
multiple plan components that address affected EGUs in each respective
ISO or RTO. The EPA is seeking comment on this idea. States that are
outside the footprint of an ISO or RTO may benefit from consulting with
other relevant planning authorities when preparing state plans. We are
also requesting comment on this idea.
3. Quantifiable and Verifiable Emission Performance
The third criterion for approvability is that a state plan specify
how the effects of each state plan measure will be quantified and
verified. The EPA proposes that all plans must specify how
CO2 emissions from affected EGUs are monitored and reported.
The EPA is proposing that both mass-based and rate-based plans must
include CO2 emission monitoring, reporting, and
recordkeeping requirements for affected EGUs, as specified in the
emission guidelines. A rate-based plan must also include monitoring,
reporting, and recordkeeping requirements for useful energy output from
affected EGUs (electricity and useful thermal output), as specified in
the emission guidelines. With one exception, these proposed
requirements are consistent with those in the proposed EGU Carbon
Pollution Standards for New Power Plants. See 79 FR 1430-1519 (January
8, 2014). The exception is that we are proposing that useful energy
output be measured in terms of net output rather than gross output, as
discussed below.
For state plans that include other measures that avoid EGU
CO2 emissions, such as RE and demand-side EE measures, the
state will also need to include quantification, monitoring, and
verification provisions in its plan for these measures, which may vary
depending on the types of requirements included in the specific plan,
as specified in the emission guidelines. This may include, for example,
quantification, monitoring, and verification of RE generation and
demand-side EE energy savings under a rate-based approach.\285\
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\285\ Considerations for quantification, monitoring, and
verification of RE and demand-side EE measures are addressed in
Section VII.F.4 of this preamble and in the State Plan
Considerations TSD.
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4. Reporting and Corrective Actions
The fourth criterion for approval is that a state plan must (i)
specify a process for annual reporting to the EPA of overall plan
performance and implementation (including compliance of affected
entities with applicable emission standards) during the plan
performance periods, and (ii) include a process and schedule for
implementing corrective measures if reporting shows that the plan is
not achieving the projected level of emission performance. We solicit
comment on whether the latter process should include the adoption of
new plan measures and subsequent resubmission of the plan to the EPA
for review and approval, or whether the process should specify the
implementation of measures that are already included in the approved
plan in the event that the projected level of performance is not being
achieved. We also solicit comment on the point at which such a process
and schedule would be triggered, such as at the end of a multi-year
plan performance period if emission performance is not met, or at
specified interim stages within a multi-year plan performance period.
For plans with self-correcting mechanisms, the agency is not proposing
that requirements for corrective measures be included in the plan. All
of these considerations are addressed in more detail above in Section
VIII.B.2.
The agency is also proposing that a state plan specify appropriate
periodic reporting requirements for each affected entity in a state
plan that will be reported at least annually, electronically, and
disclosed on a state database accessible by the public and the EPA. The
EPA is requesting comment on the appropriate scope of these reporting
requirements and whether the reports should also be directly submitted
by the affected
[[Page 34911]]
entities to the EPA, as well as to the state.
D. State Plan Components
The EPA is proposing that an approvable plan must meet the
approvability criteria described above and include the twelve state
plan components summarized below, consistent with additional specific
requirements explained elsewhere in this notice. Plans must comply with
the EPA framework regulations at 40 CFR 60.23-60.29, except as
specified otherwise by these emission guidelines. These requirements
apply both to individual state plans and multi-state plans.
For states wishing to participate in a multi-state plan, the EPA is
proposing that only one multi-state plan would be submitted on behalf
of all participating states. The joint submittal would be signed by
authorized officials for each of the states participating in the multi-
state plan and would have the same legal effect as an individual
submittal for each participating state. The joint submittal would
adequately address plan components that apply jointly for all
participating states and for each individual state in the multi-state
plan, including necessary state legal authority to implement the plan,
such as state regulations and statutes. Because the multi-state plan
functions as a single plan, each of the required plan components
described below (e.g., plan performance levels, program implementation
milestones, emission performance checks, and reporting) would be
designed and implemented by the participating states on a multi-state
basis.
We are also seeking comment on two additional options for multi-
state plan submittals. These options could potentially provide states
with flexibility in addressing contingencies where one or more states
submit plan components that are not approvable. In such instances,
these options would simplify EPA approval of remaining common or
individual portions of a multi-state plan. These options might also
address contingencies during plan development where a state fails to
finalize its participation in a multi-state plan, with minimal
disruption to the submittals of the remaining participating states.
First, the EPA is seeking comment on whether states participating
in a multi-state plan should also be given the option of providing a
single submittal--signed by authorized officials from each
participating state -- that addresses common plan elements. Individual
participating states would also be required to provide individual
submittals that provide state-specific elements of the multi-state
plan. Both the common multi-state submittal and each individual
participating state submittal would be required to address all twelve
plan components described below (even if only through cross reference
to either the common submittal or individual submittals, as
appropriate). Under this approach, the combined common submittal and
each of the individual participating state submittals would constitute
the multi-state plan submitted for EPA review.
Second, the EPA is seeking comment on an approach where all states
participating in a multi-state plan separately make individual
submittals that address all elements of the multi-state plan. These
submittals would need to be materially consistent for all common plan
elements that apply to all participating states, and would also address
individual state-specific aspects of the multi-state plan. Each
individual state plan submittal would need to address all twelve plan
components.
The EPA proposes that each plan must have the following twelve
components, except as indicated otherwise for self-correcting plans:
1. Identification of Affected Entities (Affected EGUs and Other
Responsible Parties)
A state plan must list the individual affected EGUs in the state
that are subject to the plan and provide an inventory of CO2
emissions from those units (for the most recent calendar year prior to
plan submission for which data are available), and identify any other
affected entities in a state plan with responsibilities for
implementation and enforceable obligations under the plan.
2. Description of Plan Approach and Geographic Scope
The state plan must describe its approach and geographic scope,
including whether the state will achieve its required level of
CO2 emission performance on an individual state basis or
jointly through a multi-state demonstration.
3. Identification of State Emission Performance Level
The state plan must identify the state's proposed emission
performance level, which will either be the rate-based CO2
emission goal identified for the state in the emission guidelines or a
translation of the rate-based goal to a mass-based goal.
A state plan must identify the rate-based or mass-based level of
emission performance that must be met through the plan, (expressed in
numeric values, including the units of measurement for the level of
performance, such as pounds of CO2 per net MWh of useful
energy output or tons of CO2). As noted, in the emission
guidelines, the EPA will establish the state goal in the form of a
CO2 emission rate, and the state may, for its emission
performance level, either adopt that rate or translate it into a mass-
based goal. If the plan adopts a mass-based goal, the plan must include
a description of the analytic process, tools, methods, and assumptions
used to translate from the rate-based goal to the mass-based goal.
The EPA is proposing that multiple states could jointly demonstrate
emission performance by affected EGUs. For these multi-state
approaches, states would demonstrate emission performance by affected
EGUs in aggregate with partner states. For states participating in a
multi-state approach, the individual state performance goals in the
emission guidelines would be replaced with an equivalent multi-state
performance goal. For example, states taking a rate-based approach
would demonstrate that all affected EGUs subject to the multi-state
plan achieve a weighted average CO2 emission rate that is
consistent, in aggregate, with an aggregation of the state-specific
rate-based CO2 emission performance goals established in the
emission guidelines that apply to each of the participating states. If
states were taking a mass-based approach, participating states would
demonstrate that all affected EGUs subject to the multi-state plan emit
a total tonnage of CO2 emissions consistent with a
translated multi-state mass-based goal. This multi-state mass-based
goal would be based on translation of an aggregation of the state-
specific rate-based CO2 emission performance goals
established in the emission guidelines that apply to each of the
participating states.
The EPA is seeking comment on two options for calculating a
weighted average, rate-based CO2 emission performance goal
for multiple states. Under the first option, the weighted average
emission rate goal for a group of participating states is computed
using each state's emission rate goal from the emission guidelines and
the quantity of electricity generation by affected EGUs in each of
those states during the 2012 base year that the EPA used in calculating
the state-specific goals. Different levels would be computed for the
interim and final goals. This approach is consistent with the method
used to calculate the state-specific, rate-based emission performance
goals. However, it does not address the fact
[[Page 34912]]
that the weighted average emission rate performance goal for multiple
states may be influenced significantly by the weighting of electricity
generation from affected EGUs in different states. This mix of
generation among affected EGUs in different states could differ
significantly during the plan performance periods from that during the
2012 base year.
Under the second option, the weighted average emission rate goal
for a group of participating states is computed using each state-
specific emission rate goal and the quantity of projected electricity
generation by affected EGUs in each state. The calculation would be
performed for the 2020 through 2029 period to produce a multi-state
interim goal, and for 2030 to produce a multi-state final goal. This
projection of electricity generation by affected EGUs would be for a
reference case that does not include application of either the state-
specific rate-based emission performance goals for the participating
states or the requirements, programs, and measures included in the
multi-state plan. This approach addresses the fact that the mix of
generation among affected EGUs in different states could differ
significantly during the plan performance periods from that during the
2012 base year. As a result, it would base the weighted average goal in
part on the anticipated business-as-usual mix of generation by affected
EGUs across the multiple states during the plan performance period.
However, this approach could also significantly alter the weighted
average performance goal based on projected retirements of affected
EGUs in one or more states.
Under both options, the rate-based multi-state goal could be
translated to a mass-based goal. These options, and the procedure for
translation to a mass-based goal, are discussed in more detail in the
Projecting EGU CO2 Emission Performance in State Plans TSD.
We are requesting comment on whether, to assist states that seek to
translate the rate-based goal into a mass-based goal, the EPA should
provide a presumptive translation of rate-based goals to mass-based
goals for all states, for those who request it, and/or for multi-state
regions. As another alternative, the EPA could provide guidance for
states to use in translating a rate-based goal to a mass-based goal for
individual states and for multi-state regions. This could include
information about acceptable analytical methods and tools, as well as
default input assumptions for key parameters that will likely influence
projections, such as electricity load forecasts and projected fossil
fuel prices. Under this approach, the EPA might also provide a
coordinating function in addressing the assumptions applied by multiple
states within a grid region, acknowledging that assumptions about state
programs across a broader grid region that are included in an analysis
scenario may influence projections of CO2 emissions by
affected EGUs in one or more particular states in the grid region. The
agency is seeking comment on the process for establishing mass-based
emission goals, including the options summarized above for the EPA's
and states' roles in the translation process.
Technical considerations involved in translating from rate-based
goals to mass-based goals are discussed in detail in the Projecting EGU
CO2 Emission Performance in State Plans TSD. The TSD
includes a discussion of possible acceptable analytical methods, tools,
and key assumption inputs that will influence projections. The agency
invites comment on these technical considerations.
4. Demonstration That the Plan Is Projected To Achieve the State's
Emission Performance Level
A state plan must demonstrate that the actions taken pursuant to
the plan are, when taken together, projected to achieve emission
performance by affected entities that, on average, will meet the
state's required emission performance level for affected EGUs during
the initial 2020-2029 plan performance period, and will meet the
required final emission performance level in 2030. This demonstration
will include a detailed description of the analytic process, tools, and
assumptions used to project future CO2 emission performance
by affected EGUs under the plan and the results of the analysis.
Considerations related to projecting the emission performance of
affected EGUs under a state plan are discussed in section VIII.F.7 and
in the Projecting EGU CO2 Emission Performance in State
Plans TSD.
5. Milestones
As described in greater detail in Section VIII.B.2.d., state plans
must include periodic programmatic milestones to show progress in
program implementation if the plan is not self-correcting (i.e., does
not inherently require both interim progress and the full level of
required emission performance in a manner that is federally enforceable
against affected EGUs). These programmatic milestones with specific
dates for achievement should be appropriate to the programs and
measures included in the plan.
In addition, the state plan demonstration will indicate the plan's
intended trajectory of emission performance improvement. As described
in Section VIII.B.2.d., each year during the interim performance
period, beginning in 2022 the state must compare the collective
emission performance achieved by affected entities in the state during
the previous two-year period with performance projected in the state
plan. If actual emission performance is not within 10 percent of
original projections, the state must submit a report by the July 1
following the end of the two-year period (submitted as part of the
state's annual report on plan performance described below in section
VIII.D.10) to explain reasons for the deviation and specify the
corrective actions that will be taken to ensure that the required level
of emission performance in the plan will be met.
6. Corrective Measures
For a plan that does not include self-correcting mechanisms, the
plan must also specify corrective measures that will be implemented if
the state's progress in achieving its level of performance for affected
EGUs falls short of what is projected under the plan, as well as a
process and schedule for implementing any such measures. The agency
requests comment on the amount of emission rate improvement or emission
reduction that the corrective measures included in the plan must be
designed to achieve (e.g., measures sufficient to address a 10 percent
performance deficiency). The agency also seeks comment on whether the
emission guidelines should establish a deadline for implementation of
corrective measures (e.g., two years from the July 1 deadline described
above for reporting the deficiency as part of the state's annual report
on plan performance). Corrective measure provisions are discussed in
more detail above in section VIII.B.2.d and in section VIII.B.2.f.
7. Identification of Emission Standards and Any Other Measures
A state plan must identify the affected entities to which each
emission standard applies (e.g., individual affected EGUs, groups of
affected EGUs, all the state's affected EGUs in aggregate, other
affected entities that are not EGUs), as well as any implementing and
enforcing measures for such standards, and describe each emission
standard and the process for demonstrating compliance with it pursuant
to state regulations or another legal instrument, including the
schedule
[[Page 34913]]
for compliance for each affected entity. In its proposed Carbon
Pollution Standards (79 FR 1430-1519, January 8, 2014), the EPA
proposed that the appropriate averaging time for an emission standard
for new EGUs be no longer than 12 months. Similarly, the EPA proposes
here that an appropriate averaging time for any rate-based emission
standard for affected EGUs and/or other affected entities subject to a
state plan is no longer than 12 months within a plan performance period
and no longer than three years for a mass-based standard. We also
solicit comment on longer and shorter averaging times for emission
standards included in a state plan.
8. Demonstration That Each Emission Standard Is Quantifiable, Non-
Duplicative, Permanent, Verifiable, and Enforceable
In developing its CAA section 111(d) plan, a state must ensure that
its plan is enforceable and in conformance with the CAA. As discussed
in section VIII.C.1, we are seeking comment on the appropriateness of
existing EPA guidance on enforceability in the context of state plans
under CAA section 111(d), considering the types of affected entities
that might be included in a state plan.\286\ This guidance serves as
the foundation for the types of monitoring, reporting, and limits that
the EPA has found can be, as a practical matter, enforced, and set
forth the general principle that a requirement that is enforceable as a
practical matter is one that is quantifiable, verifiable,
straightforward and is calculated over as short a term as reasonable.
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\286\ EPA guidance on enforceability includes: (1) September 23,
1987 memorandum and accompanying implementing guidance, ``Review of
State Implementation Plans and Revisions for Enforceability and
Legal Sufficiency,'' (2) August 5, 2004 ``Guidance on SIP Credits
for Emission Reductions from Electric-Sector Energy Efficiency and
Renewable Energy Measures,'' and (3) July 2012 ``Roadmap for
Incorporating Energy Efficiency/Renewable Energy Policies and
Programs into State and Tribal Implementation Plans, Appendix F.''
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As discussed in section VIII.F.1, the EPA is seeking comment on
whether the agency should provide guidance on enforceability
considerations related to requirements in a state plan for entities
other than affected EGUs (and if so, which types of entities). Also, as
discussed in section VIII.F.4, the EPA intends to develop guidance for
evaluation, monitoring, and verification (EM&V) of renewable energy and
demand-side energy efficiency programs and measures incorporated in
state plans.
For each emission standard, a plan must describe how it is
quantifiable, non-duplicative, permanent, verifiable, and enforceable
with respect to an affected entity. An emission standard is
quantifiable if it can be reliably measured, using technically sound
methods, in a manner that can be replicated. These issues are discussed
further in Section VIII.F.4 and in the State Plan Considerations TSD.
An emission standard is non-duplicative with respect to an affected
entity if it is not already incorporated in another state plan, except
in instances where incorporated in another state as part of a multi-
state plan. An example of a duplicative emission standard would occur
where recognition of avoided CO2 emissions from, for
example, a wind farm, could be applied in more than one state's CAA
section 111(d) plan, except in the case of a multi-state plan where
recognition is assigned among states or emission performance is
demonstrated jointly for all affected EGUs subject to the multi-state
plan. This does not mean that measures in an emission standard cannot
also be used for other purposes. For example, if a state wished to take
credit for CO2 emissions avoided due to electric generation
from a new wind farm, those avoided emissions could be considered non-
duplicative and included for purposes of CAA section 111(d), even if
electric generation from that wind farm was also being used to generate
renewable energy certificates (RECs) to comply with the state's RPS
requirements. It also does not mean that a single affected entity could
not be subject to similar emission standards in different state plans.
For example, an affected entity might be an electric distribution
utility that has a service territory that crosses state lines. This
entity might be subject to a separate state demand-side EE requirement
for electricity supplied in each of the states where it serves
electricity customers. In this instance, the same company could be an
affected entity subject to a different state demand-side EE requirement
in each state plan, without these emission standards in each plan being
considered duplicative. The EPA solicits comment on whether an emission
reduction becomes duplicative (and therefore cannot be used for
demonstrating performance in a plan) if it is used as part of another
state's demonstration of emission performance under its CAA section
111(d) plan.
An emission standard is permanent if the standard must be met for
each applicable compliance year or period, or replaced by another
emission standard in a plan revision, or the state demonstrates in a
plan revision that the emission standard is no longer necessary for the
state to meet its required emission performance level for affected
EGUs.
An emission standard is verifiable if adequate monitoring,
recordkeeping and reporting requirements are in place to enable the
state and the Administrator to independently evaluate, measure, and
verify compliance with it. This is discussed further in Section
VIII.F.4 and in the State Plan Considerations TSD. An emission standard
is enforceable if: (1) It represents a technically accurate limitation
or requirement and the time period for the limitation or requirement is
specified, (2) compliance requirements are clearly defined, (3) the
affected entities responsible for compliance and liable for violations
can be identified, (4) each compliance activity or measure is
practically enforceable in accordance with EPA guidance on practical
enforceability (as discussed in Section VIII.F.1 of this preamble), and
the Administrator and the state maintain the ability to enforce against
violations and secure appropriate corrective actions pursuant to CAA
sections 113(a)-(h).
9. Identification of Monitoring, Reporting, and Recordkeeping
Requirements
The state plan must describe the CO2 emission
monitoring, reporting, and recordkeeping requirements for affected
EGUs, including requirements for monitoring and reporting of useful
energy output if a state plan is taking a rate-based approach. The EPA
is proposing that each plan include monitoring, reporting, and
recordkeeping requirements for CO2 emissions and useful
energy output (if applicable) that are materially consistent with the
requirements specified in the emission guidelines. State plans with a
rate-based form of the emission performance level must require affected
EGUs to report hourly net energy output (including net MWh generation,
and where applicable, useful thermal output) to the EPA on an annual
basis.
Most affected EGUs already monitor CO2 emissions under
40 CFR Part 75 and report the data using the EPA's Emission Collection
and Monitoring Plan System (ECMPS), which would generally satisfy
CO2 emission reporting requirements under the proposed
guidelines. However, we are seeking comment on two possible adjustments
to the Part 75 Relative Accuracy Test Audit (RATA) requirements for
steam EGU stack gas flow monitors that can affect reported
CO2 emissions. The first possible adjustment would be to
require use of the most accurate RATA
[[Page 34914]]
reference method for specific stack configurations, while the second
possible adjustment would be to require a computation adjustment when
an EGU changes RATA reference methods. The rationale for these possible
adjustments is described further in the Part 75 Monitoring and
Reporting Considerations TSD available in the docket.
We are also proposing monitoring and reporting protocols for net
energy output under 40 CFR Part 75 that would allow the ECMPS to be
used for purposes of meeting the net energy output reporting
requirement. Affected facilities with multiple generators (e.g.,
combined cycle facilities) would be required to report the electric
output from all generators. The proposed protocols include a default
apportionment procedure for multi-EGU facilities under which the net
generation of each EGU at the facility would be determined as the net
generation of the facility multiplied by the ratio of the EGU's gross
generation to the sum of the gross generation for all EGUs at the
facility. (In the case of EGUs producing both electric energy output
and useful thermal output, the apportionment procedure would include a
thermal-to-electric energy conversion calculation as provided in the
proposed EGU GHG NSPS regulations.\287\) We solicit comment on whether
EGUs producing both electric energy output and useful thermal output
should be required to report both electric and useful thermal output.
In addition, the proposed protocols would allow facilities to use
alternative apportionment procedures with EPA approval. We invite
comment on the proposal for reporting of net rather than gross energy
output and on the proposed protocols. Specifically, we are seeking
comment on: Any existing protocols for reporting net output (FERC,
NERC, etc.); electricity meter specifications; electricity meter
quality assurance testing and reporting procedures; apportionment
procedures for parasitic load at multi-unit facilities; treatment of
externally provided electricity; and monitoring and quality assurance
testing and reporting procedures for non-electric energy output at CHP
units. (Options regarding these topics are discussed in the TSD
mentioned above.) Also, consistent with the requests for comment in the
proposed CAA section 111(b) GHG NSPS regulations for modified and
reconstructed sources, we invite comment here on a range of two-thirds
to 100 percent credit for useful thermal output in the final rule, or
other alternatives to better align incentives with avoided emissions.
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\287\ 70 FR 1429-1519; January 8, 2014.
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A state plan that contains other emission standards, in addition to
emission limits applicable to affected EGUs, must include additional
reporting and recordkeeping requirements related to these other
measures. These reporting and recordkeeping requirements will consist
of the data necessary for each affected entity to demonstrate
compliance with its obligations. This could include, for example,
reporting of MWh electricity savings achieved by an electric
distribution utility under an end-use energy efficiency resource
standard and utility compliance with requirements of the standard.
These requirements might also include comparable reporting by an
electric distribution utility of renewable energy certificates (RECs)
held, or renewable energy purchased or generated, under a renewable
energy portfolio standard, and compliance with the standard. This is
discussed further in Section VIII.F.5 and the State Plan Considerations
TSD.
The EPA is proposing that state plans must include a record
retention requirement of ten years, and we request comment on this
proposed timeframe.
10. Description of State Reporting
A state plan must provide that the state will submit reports to the
EPA detailing plan implementation and progress, including the actions
taken by the state, affected EGUs, and any other affected entities
under the plan; the status of compliance by affected EGUs and any other
affected entities with their obligations under the plan; current
aggregate and individual CO2 emission performance by
affected EGUs during the reporting year and prior reporting years; and
any additional measures applied under the plan during the reporting
period. The state plan must describe the process, timing, and content
for these reports. The EPA is proposing that an annual report is due no
later than the July 1 following the end of the reporting year.
While some of the proposed reporting requirements such as reporting
of EGU emissions (which can be done through existing reporting
mechanisms) would not place additional burdens on states, others may
require assembling information that is being reported under state
programs into a single report. For example, in the case of a rate-based
state plan that calls for adjusting the actual emission rate of the
state's affected EGUs based on emissions avoided through renewable
energy or end-use energy efficiency programs, the requirement for
comparing actual plan performance against projected plan performance
requires the state to incorporate information on results achieved by
those programs each year. This emission performance comparison serves
as the basis for showing either that a state plan is on track or that
corrective measures are needed. Another reporting element is a list of
facilities and their compliance status. The EPA is requesting comment
on the appropriate frequency of reporting of the different proposed
reporting elements, considering both the goals of minimizing
unnecessary burdens on states and ensuring program effectiveness. In
particular, the agency requests comment on whether full reports
containing all of the report elements should only be required every two
years.
In addition, the EPA is soliciting comment on whether these reports
should be submitted electronically, to streamline transmission.
11. Certification of State Plan Hearing
A state plan must provide certification that a hearing on the state
plan was held, a list of witnesses and their organizational
affiliations, if any, appearing at the hearing, and a brief written
summary of each presentation or written submission pursuant to the
requirements of the EPA framework regulations at 40 CFR 60.23-60.29.
12. Supporting Material
The state must provide supporting material and technical
documentation related to applicable components of the plan. In its
plan, a state must adequately demonstrate that it has the legal
authority for each implementation and enforcement component that it has
included in its plan as part of a federally enforceable emission
standard. A state can make such a demonstration by providing supporting
material related to the state's legal authority used to implement and
enforce each component of the plan, such as statutes, regulations,
public utility commission orders, and any other applicable legal
instruments.
A state plan must also provide analytical materials used in
translating a rate-based goal to a mass-based goal (if a translation is
included), analytical materials used in projecting emission performance
that will be achieved through the plan, relevant implementation
materials, and any additional technical requirements and guidance the
state proposes to use to implement elements of the plan.
[[Page 34915]]
E. Process for State Plan Submittal and Review
1. Overview
Under the framework regulations, state plans would be due nine
months after finalization of the emission guidelines. 40 CFR
60.23(a)(1). The President in his June 25, 2013 Memorandum specified
that states should submit plans by June 30, 2016, which would provide
states thirteen months. During the outreach process, many states
expressed concern that this was not sufficient time to prepare and
submit a state plan to the EPA. States commented that additional time
was needed to accommodate, among other things, state legislative and
rulemaking schedules, coordination among states involved in multi-state
plans, coordination with third parties, and the complex technical work
needed to develop a state plan. The EPA recognizes that state
administrative procedures can be lengthy, some states may need new
legislative authority, and states planning to join in a multi-state
plan will likely need more than thirteen months to get necessary
elements in place. Balanced against that concern, however, is the
urgency of addressing carbon emissions and the fact that there are
certain steps we believe states can take within thirteen months to set
themselves on a clear path to adoption of a complete plan. Therefore,
the EPA is proposing a plan submittal process with a submittal date of
June 30, 2016 (thirteen months after the expected finalization date of
the emission guidelines), which provides additional time to submit a
complete plan to the EPA after June 30, 2016, when justified. Part of
that justification would include the state's demonstration of having
taken meaningful steps during the first thirteen months toward
submitting a complete plan. This approach involves the option that we
refer to as an initial submittal, followed by submittal of a complete
state plan no later than either June 30, 2017 for single-state plans or
June 30, 2018 for multi-state plans.
In addition, for states wishing to participate in a multi-state
plan, the EPA is proposing that only one multi-state plan would be
submitted on behalf of all participating states, provided it is signed
by authorized officials for each of the states participating in the
multi-state plan and contains the necessary regulations, laws, etc. for
each state in the multi-state plan. In this instance, the joint
submittal would have the same legal effect as an individual submittal
for each participating state.
2. State Plan Submittal and Timing
The EPA framework regulations (40 CFR 60.23) require that state
plans be submitted to the EPA within nine months of promulgation of the
emission guidelines, unless the EPA specifies otherwise.\288\ In view
of the potential that these plans may require states to develop new
regulatory or statutory authority, we are proposing that each state
must submit a plan to the EPA by June 30, 2016, which is more than one
year after the expected finalization date of the emission guidelines.
The state may submit a complete plan, or if justified, an initial plan
that documents the state's progress in preparing a complete plan. To
qualify for an extension of the June 30, 2016 deadline for submitting a
complete plan, the state must submit an initial plan that demonstrates
the state is on track to develop a complete plan and that includes
meaningful steps that clearly commit the state to complete an
approvable plan.
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\288\ 40 CFR 60.23(a)(1).
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The EPA proposes that approvable justifications for seeking an
extension beyond 2016 for submitting a complete plan include: A state's
required schedule for legislative approval and administrative
rulemaking, the need for multi-state coordination in the development of
an individual state plan, or the process and coordination necessary to
develop a multi-state plan. The EPA is requesting comment on other
circumstances for which an extension of time would be appropriate. We
are also seeking comment on whether some justifications for extension
should not be permissible.
If a state submits an initial state plan by June 30, 2016, and it
meets the minimum requirements for an initial state plan, as specified
in the plan guidelines, then the deadline extension for submitting a
complete plan that the state requested will be deemed granted. If the
EPA determines that the initial plan does not meet the guidelines, the
EPA will notify the state by letter, within 60 days, that the agency
cannot approve the state's initial plan as submitted. The EPA believes
this approach is authorized by, and consistent with, section 60.27(a)
of the implementing regulations.
If the EPA approves a two-year extension to June 30, 2018, for a
state developing a multi-state plan, the state would be required to
provide one update, on June 30, 2017, on its progress toward milestones
and schedules in the initial plan for developing and submitting a
complete plan. We are requesting comment on this approach and the
timing and frequency of updates that the state must provide.
3. Components of an Initial State Plan Submittal and Approvability
Criteria
As noted, if a state is unable to prepare and submit a complete
plan by June 30, 2016, the state must make an initial submittal by that
date. To be approved, the EPA proposes that the initial plan must
address all components of a complete plan, including identifying which
components are not complete. For incomplete components, an approvable
initial submittal must contain a comprehensive roadmap outlining the
path to completion, including milestones and dates. We recognize that
certain options that states may choose involve more analytic effort to
precisely demonstrate sources of emission reductions than other
options.
The EPA is proposing that the state must provide an opportunity for
public comment on a substantial draft of its initial submittal. The EPA
proposes that this public comment opportunity will not be governed by
the procedural requirements of the framework regulations that apply to
the state's adoption of a complete plan, such as the requirement that
the state hold a public hearing. 40 CFR 60.23(c)-(f). An initial plan
might not include any legally enforceable provisions that the state
would have adopted through its administrative or legislative processes,
which generally provide for public input. Therefore, to ensure that the
public has an opportunity to understand and inform the initial plan,
the EPA is proposing that prior to submittal on June 30, 2016 the state
must have provided a reasonable opportunity for public comment on a
substantial draft of the initial submittal, with notice to the EPA of
that comment period. The EPA can use this comment opportunity to advise
the state whether it is on track to submit an approvable initial plan.
When the state submits its initial plan, it must provide the EPA with a
response to any significant comments it received on issues relating to
the approvability of the initial plan so that the EPA can fully assess
whether it is approvable.
To be approvable, the initial plan must include the following
information:
A description of the plan approach and progress to date in
developing a complete plan.
Initial quantification of the level of emission
performance that will be achieved through the plan.
A commitment to maintain existing measures that limit or
avoid CO2 emissions (e.g., renewable energy
[[Page 34916]]
standards, unit-specific limits on operation or fuel utilization), at
least until the complete plan is approved.
A comprehensive roadmap for completing the plan, including
process, analytical methods, and schedule (with milestones) specifying
when all necessary plan components will be complete (e.g.,
demonstration of projected plan performance; implementing legislation,
regulations and agreements; any necessary approvals).
Identification of existing programs, if any, the state
intends to rely on to meet its emission performance level.
Identification of executed agreements with other states
(e.g., memorandum of understanding (MOU)), if a multi-state approach is
being pursued.
A commitment to submit a complete plan by no later than
the applicable required date and explanation of actions the state will
take to show progress in addressing incomplete plan components.
A description of all steps the state has already taken in
furtherance of actions needed to finalize a complete plan (e.g., copies
of draft or proposed regulations, draft or introduced legislation, or
draft implementation materials).
Evidence of an opportunity for public comment and a
response to any significant comments received on issues relating to the
approvability of the initial plan.
The EPA is soliciting comment on whether there are other elements
that a state must include in its initial submittal to qualify for a
date extension. Specifically, the EPA requests comment on whether the
guidelines should require a state to have taken significant, concrete
steps toward adopting a complete plan for the initial plan to be
approvable. For example, while it may be difficult for a state to
complete its administrative or legislative process within thirteen
months, it may be reasonable to require that a state must document that
it has at least proposed any necessary regulations and introduced any
necessary legislation within the first thirteen months to qualify for
additional time to submit a complete plan.
For states participating in a multi-state program, the initial
submittal should include executed agreements among the participating
states and a road map for both design of the multi-state program and
its implementation at the state level. The RGGI provides an example of
such an approach. The RGGI participating states signed a Memorandum of
Understanding (MOU) in December 20, 2005, in which the states
``express[ed] their mutual understandings and commitments''.\289\ The
MOU included a detailed outline of the multi-state emission budget
trading program, which served as a guide for drafting a model rule. The
MOU also included commitments by the participating states to draft and
finalize the model rule by specified dates, and a commitment to seek to
establish in statute and/or regulation a program materially consistent
with the model rule in each state by a specified date.\290\ The MOU
also included a commitment to launch the program by January 1, 2009 in
all states and specified a process for establishing a non-profit
organization to assist the states in administering the regional aspects
of the program. In addition, prior to execution of the MOU, the RGGI
states committed, through letters from the Governors of participating
states, to engage in the development of a market-based program to
reduce CO2 emissions from power plants. This was followed by
publication of an action plan for tasks leading up to agreement on the
basic structure of the program, which was ultimately formalized in the
MOU.
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\289\ Regional Greenhouse Gas Initiative Memorandum of
Understanding, available at http://rggi.org/design/history/mou. Two
states subsequently signed the original MOU in early 2007 and a
third joined the program later that year through an amendment of the
MOU; one of the original states withdrew from the MOU in late 2011.
\290\ The model rule specified elements that needed to be
consistent across states for the program to function, as well as
areas where state rules could differ (e.g., the method used for
allocating CO2 allowances). For more information, see
Regional Greenhouse Gas Initiative Model Rule, available at http://rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Rule_FINAL.pdf.
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4. Process for EPA Review of State Plans
Following the June 30, 2016, deadline for state plan submittals,
the EPA will review plan submittals for approvability. For a state that
submits an initial state plan by June 30, 2016, and requests an
extension of the deadline for the submission of a complete state plan,
the EPA will determine if the initial plan submittal meets the minimum
requirements for an initial state plan. If it meets the minimum
requirements for an initial state plan, as specified in the emission
guidelines, the state's request for a deadline extension to submit a
complete plan will be deemed granted, and the complete plan must be
submitted to the EPA by no later than June 30, 2017 or June 30, 2018 as
appropriate.
After receipt of a complete plan submittal, the EPA proposes that
the agency will review the plan and, within twelve months, approve or
disapprove the plan through a notice-and-comment rulemaking process,
similar to that used for approving state implementation plan submittals
under section 110 of the CAA. The framework regulations currently
provide for the EPA to act on a complete plan within four months. 40
CFR 60.27(b). The EPA proposes that for plans under these guidelines,
the agency will act on a complete plan within twelve months to provide
adequate time for rulemaking procedures.
Currently, the EPA's framework regulations do not explicitly
provide for the EPA to use the different forms of approval actions
Congress introduced into the SIP program in the 1990 Clean Air Act
Amendments. The EPA is taking comment on whether, for complete state
plans under these guidelines, the agency may use two approval
mechanisms provided for in CAA sections 110(k)(3) and (4), 42 U.S.C.
7410(k)(3) and (4). CAA section 111(d)(1) provides that the EPA shall
establish ``a procedure similar to that provided by section 7410 of
this title [section 110 of the Act].'' The EPA is considering whether
to update the procedures for acting on complete state plans under the
guideline to reflect the enhancements Congress included in CAA section
110 for agency actions on state implementation plans.
The first mechanism is a partial approval/partial disapproval.
Where a CAA section 111(d) plan includes severable provisions, some of
which are approvable and some of which are not, the EPA is taking
comment on whether the agency should interpret the CAA as providing the
flexibility to approve those elements that meet the requirements of
this guideline, while disapproving those elements that do not. Any plan
that is partially approved and partially disapproved would not fully
discharge the state's obligation to submit a fully approvable plan, but
the partial approval would make federally enforceable those elements of
the state's plan that comply with these guidelines.
The second mechanism is a conditional approval. Where a CAA section
111(d) plan is substantially approvable and requires only minor
amendments to fully meet the requirements of these guidelines, the EPA
is taking comment on whether the agency should interpret the CAA as
providing the flexibility to approve that plan on the condition that
the state commits to curing the minor deficiencies within one year. Any
such conditional approval would be treated as a disapproval if the
state fails to comply with its commitment. During the year following
the conditional approval while the state works to cure
[[Page 34917]]
the deficiency identified in the condition, the state's plan would be
federally enforceable.
The EPA has seen that these mechanisms have proven useful when
reviewing and acting on state implementation plan submittals under CAA
section 110. They allow the state, the EPA, and citizens to enforce
good elements of plans or plans that are substantially complete while
the state and the EPA work together to put in place a fully approvable
plan. The agency notes that complete plan submittals under these
guidelines, like SIPs that implement air quality standards, also may
contain multiple program elements.
5. Failure To Submit a Complete Plan
If a state fails to submit a complete plan by the applicable
deadline, the EPA will notify the state by letter of its failure to
submit. The EPA will publish a Federal Register notice informing the
public of any such notifications. When appropriate, the agency may
batch the publication of such notices periodically to simplify
publication.
6. Modification of an Approved State Plan
During the course of implementation of an approved state plan, a
state may wish to update or alter one or more of the enforceable
measures in the state plan, or replace certain existing measures with
new measures. The EPA proposes that the state may revise its state plan
provided that the revision does not result in reducing the required
emission performance for affected EGUs specified in the original
approved plan. In other words, no ``backsliding'' on overall plan
emission performance through a plan modification would be allowed.
If the state wishes to revise enforceable measures in its approved
state plan, the EPA proposes that the state must submit the revised
enforceable measures to the EPA and demonstrate that the revised set of
enforceable measures in the modified plan will result in emission
performance at affected EGUs that is equivalent to or better than the
level of emission performance required by the original state plan. In
the case of minor changes to enforceable measures, this showing may be
a simple explanation of why the changes will not alter the emission
performance of affected EGUs under the state plan, or will clearly
improve the emission performance of affected EGUs under the state plan.
In the case of more substantive changes to enforceable measures, or
substitution of a new measure for an old measure, new projections of
emission performance under the modified plan would be needed to
demonstrate that the modified plan will meet the required level of
emission performance for affected EGUs specified in the original
approved plan. The EPA requests comment on whether, for such new
projections of emission performance, the projection methods, tools, and
assumptions used should match those used for the projection in the
original demonstration of plan performance, or should be updated to
reflect the latest data and assumptions, such as assumptions for
current and future economic conditions and technology cost and
performance.
7. Plan Templates and Electronic Submittal
The EPA is seeking comment on the creation of a template for
initial and complete state plan submittals. A plan template would
provide a framework that includes all of the necessary components for
an initial and complete submittal that could be populated by states.
This could assist states in compiling their plan submittals and
streamline EPA review by assuring greater consistency in the format and
organization of submittals. This would provide greater certainty for
states about what they need to include in a submittal and allow the EPA
to provide a quicker response to states about the completeness and
approvability of submittals. We are further seeking comment on whether
a template may be more appropriate for initial plan submittals than
complete plans. Initial plan submittals are likely to be more similar
across states, compared to complete plans, which may include a diverse
range of components, depending on the state plan approach.
The EPA is also seeking comment on whether it should provide for,
or require, electronic submittal of initial and complete plans. It is
the EPA's experience that the electronic submittal of information
increases the ease and efficiency of data submittal and data
accessibility. We note that a number of states have requested an
electronic submittal process for state implementation plans (SIPs)
under CAA section 110, and the EPA has implemented a pilot program with
a number of states for electronic submittal of such plans. The
Electronic State Implementation Plan Submission Pilot (eSIPS) includes
an EPA-state workgroup that has developed and will evaluate an
electronic submission process. This pilot will use the EPA's Central
Data Exchange (CDX) electronic submission system. We are seeking
comment on the suitability of such an approach for submittal of state
plans under CAA section 111(d).
F. State Plan Considerations
The EPA is proposing to give states broad discretion to develop
plans that best suit their circumstances and policy objectives. In
developing its plan, a state will need to make a number of decisions
that will require careful consideration, in order to ensure that its
plan both meets the state's policy objectives and is approvable by the
EPA. In this section, we identify several key decision points and
factors that states should consider when developing their plans.
The EPA has also prepared a TSD, titled ``State Plan
Considerations,'' that provides further information on these topics.
The agency is seeking comment on the contents of this TSD and all
aspects of the state plan decision points and factors below.
1. Affected Entities Other Than Affected EGUs
A state will need to identify each affected entity responsible for
meeting compliance obligations under its plan and the means by which
compliance with each plan requirement will be met, as well as
demonstrate that it has the legal authority to subject such entities to
the federally enforceable requirements specified in its state plan. We
are proposing that affected entities in an approvable state plan may
include: An owner or operator of an affected EGU, other affected
entities with responsibilities assigned by a state (e.g., an entity
that is regulated by the state, such as an electric distribution
utility, or a private or public third-party entity), and a state
agency, authority or entity. We are seeking comment on other
appropriate examples of affected entities beyond the affected EGUs.
While the EPA seeks to provide states with broad discretion to
develop plans that best suit their circumstances and policy objectives,
a plan that assigns responsibility to affected entities other than
affected EGUs may be more challenging to implement and enforce than a
plan with requirements assigned only to affected EGUs.
Furthermore, it may be more challenging for a state to demonstrate
that it has sufficient legal authority to subject such affected
entities other than affected EGUs to the federally enforceable
requirements specified in its state plan. We seek comment on whether
the EPA should provide guidance on enforceability considerations
related to requirements in a state plan for affected entities other
than EGUs (and if so, which such entities). The State Plan
Considerations
[[Page 34918]]
TSD provides illustrative examples of possible entities and legal
mechanisms.
2. Treatment of Existing State Programs
a. Framing Considerations
Many state officials and stakeholders have said that the EPA should
avoid structuring the CAA section 111(d) emission guidelines in a way
that would disadvantage states that already have adopted programs that
reduce CO2 emissions from EGUs. The EPA agrees with that
policy principle.
There is much less agreement among states and stakeholders on the
specifics of how existing state programs should be treated in a
demonstration that a proposed state plan will achieve the required
level of emission performance.
The EPA, starting from recent historical data, has identified the
affected EGU emission performance improvements and resulting average
emission performance levels for affected EGUs that are achievable,
considering cost, in each state over the 2020-2029 period, with
achievement of the final CO2 emission performance level by
2030.
As explained in Section VII above, the EPA's proposed state-
specific goals reflect actions that many states have already taken to
reduce or avoid EGU CO2 emissions. CO2 emission
reductions due to shifts to lower CO2-emitting power
generation are also represented in the 2012 base period that was used
to assess certain building blocks that are applied in calculating a
state emission performance goal.\291\
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\291\ For example, in such instances a significant shift to NGCC
generation prior to 2012 may result in a lower potential for further
re-dispatch to these units, as witnessed in the 2012 base period
data. This would influence the calculated rate-based emission goal
for the state, reducing the percentage improvement required relative
to the base period CO2 emission rate.
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The agency recognizes that states that have already shifted toward
lower carbon-intensity generation or ramped up demand-side EE programs
are better positioned to meet state-specific goals. For example, states
where significant shifts in generation to NGCC units have already
occurred would be closer to the generation mix reflected in the state
goals than states where NGCC capacity is not yet being operated to the
same degree. Likewise, states with relatively well-established demand-
side EE programs would be able to build on those programs more quickly
than states with less established programs, and would be closer to, or
in some cases already achieving, the level of demand-side energy
efficiency reflected in the state goals.
b. Proposed Approach for Treatment of Existing State Programs and
Measures in an Approvable State Plan
The EPA is proposing that existing state programs, requirements,
and measures,\292\ may qualify for use in demonstrating that a state
plan will achieve the required level of emission performance, provided
they meet the approvability requirements in the emission guidelines
(summarized above in Section VIII.C) and relevant requirements for plan
components in the emission guidelines (described above in Section
VIII.D). Several options for treatment of existing state programs and
measures are described below.
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\292\ An ``existing measure'' refers to a state or utility
requirement, program, or measure that is currently ``on the books.''
For the purposes of this discussion, this may include a legal
requirement that includes current and future obligations or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future in accordance with established
plans. Existing measures may have past, current, and future impacts
on EGU CO2 emissions.
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Specifically, the EPA is proposing that, for an existing state
requirement, program, or measure, a state may apply toward its required
emission performance level the emission reductions that existing state
programs and measures achieve during a plan performance period as a
result of actions taken after the date of this proposal.\293\ This
proposed approach would recognize beneficial emission impacts from
existing state programs and measures during a plan performance period.
It would do so in a way that may be generally compatible with the
forward-looking methodology that the EPA used to propose state emission
performance goals based on the BSER. By making actions taken after
proposal eligible to help meet a state's required emission performance
level, this approach would support early beneficial emission-reducing
actions. This option would ensure that actions taken after proposal of
the emission guidelines and prior to 2020 as a result of requirements
in a state plan, could be recognized as contributing toward meeting a
state's required emission performance level for affected EGUs.
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\293\ We are also proposing that this proposed limitation would
not apply to existing renewable energy requirements, programs and
measures because existing renewable energy generation prior to the
date of proposal of the emission guidelines was factored into the
state-specific CO2 goals as part of building block 3.
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In general, the agency has identified two broad options for
treatment of existing state programs and measures. As noted above, the
EPA proposes that emission reductions that existing state requirements,
programs and measures achieve during a plan performance period as a
result of actions taken after a specified date may be recognized in
determining emission performance under a state plan. While proposing
that the ``specified date'' would be the date of proposal of these
emission guidelines, the EPA also requests comment on the following
alternatives: The start date of the initial plan performance period,
the date of promulgation of the emission guidelines, the end date of
the base period for the EPA's BSER-based goals analysis (e.g., the
beginning of 2013 for blocks 1-3 and beginning of 2017 for block 4,
end-use energy efficiency), the end of 2005, or another date.
For this option, we are seeking comment on the point in time after
which such actions should be able to qualify for use during a plan
performance period, considering the method used to set state goals.
Whether this option is consistent in practice with the EPA's
application of the BSER may depend on the date or dates that are
applied for qualifying actions under existing state programs,
requirements, and measures. For example, implementation of measures
subsequent to the proposal or promulgation of the emission guidelines
may be consistent with a forward-looking goal-setting approach, as
these actions may be necessary to meet a required level of emission
performance during the plan performance period or will put a state in a
better position to meet the required level of performance. An example
is the EPA's treatment of end-use energy efficiency potential in state
goal-setting, where the energy savings achievable during the initial
plan performance period are premised in part on a ramping up of end-use
energy efficiency programs and cumulative energy savings prior to the
beginning of the plan performance period. Earlier dates may also be
consistent with a forward-looking goal-setting approach, if the goal-
setting approach is premised in part on actions that could be taken
prior to the initial plan performance period. However, inconsistency
issues may arise if the selected date is not adequately synchronized
with the goal-setting method. The EPA requests comment on whether there
is a rational basis for choosing a date that predates the base period
from which the EPA used historical data to derive state goals. The
agency generally requests comment on the appropriate date to select
under this option.
The EPA also solicits comment on a second broad option. This option
would recognize emission reductions that existing state requirements,
programs
[[Page 34919]]
and measures achieved starting from a specified date prior to the
initial plan performance period, as well as emission reductions
achieved during a plan performance period. The specified date could be,
for example: The date of promulgation of the emission guidelines; the
date of proposal of the emission guidelines; the end date of the base
period for the EPA's BSER-based goals analysis (e.g., the beginning of
2013 for blocks 1-3 and the beginning of 2017 for block 4, end-use
energy efficiency); the end of 2005; or another date.
The EPA requests comment on this option--that emission reduction
effects that occur prior to the beginning of the initial plan
performance period could be applied toward meeting the required level
of emission performance in a state plan. This approach would enable a
state to count emission improvements achieved by state programs prior
to 2020 toward its interim goal, allowing the state to begin
demonstrating emission performance earlier and follow a more gradual
emission improvement trajectory during the interim performance period
of 2020-2029. This approach would in effect allow higher emissions
during the 2020-2029 period than would occur under the proposed
approach (i.e., requiring less emission performance improvement during
that period). The rationale for this approach would be that higher
emissions in 2020-2029 would be offset by pre-2020 emission reductions
not required by the CAA section 111(d) program. However, total
emissions to the atmosphere would likely be greater under this
approach, unless the pre-2020 emission reductions that can be counted
toward the state goal are limited to reductions that would not have
occurred in the absence of the CAA section 111(d) program. To the
extent that states are able to both adopt and implement new
requirements earlier than 2020 (e.g., by 2018 or 2019), this approach
could provide an incentive for earlier emission reductions. The agency
requests comment on whether pre-2020 implementation of new requirements
would be practical for states. The agency generally requests comment on
this approach, including the conditions that should apply to pre-2020
emission reductions that would count toward the state goal.
The agency also requests comment on the alternative dates listed
above in connection with this option. We also request comment on
whether this option is inconsistent with the forward-looking method
that the EPA has proposed for establishing state goals based on the
application of the BSER.
The agency is seeking comment on whether some variation of this
approach could be justified as consistent with the EPA's proposed goal-
setting approach, as well as the general concept of the BSER and its
application in establishing state goals. In particular, we are seeking
comment on whether the emission effects of actions that are taken after
proposal or promulgation of the emission guidelines or the approval of
a state plan, but which occur prior to the beginning of the initial
state plan performance period, could be applied toward meeting the
required level of emission performance in a state plan.
c. Application of Options Under Rate-Based and Mass-Based Plan
Approaches
Under a rate-based approach, the options described above would
address the eligibility date for qualifying demand-side EE measures
that, through MWh savings, avoid CO2 emissions from affected
EGUs. Measures installed after the eligibility date could generate MWh
savings during a plan performance period, and related avoided
CO2 emissions, that could be applied toward meeting a
required rate-based emission performance level. Under the proposed
option, the eligibility date would be the date of these proposed
emission guidelines. For example, under this approach, new demand-side
EE measures installed in 2015 or later to meet an existing, on-the-
books energy efficiency resource standard (EERS) would be a qualifying
measure. However, only MWh savings beginning in 2020 and related
avoided CO2 emissions could be applied toward meeting a
required rate-based emission performance level.
Under a mass-based approach, the options described above would be
applied when establishing a reference case scenario projection that is
used to translate a rate-based goal to a mass-based goal. For example,
demand-side EE measures after a respective eligibility date would not
be included in the scenario that is used to project CO2
emissions from affected EGUs when establishing a translated mass-based
emission goal. This could be achieved by not including the incremental
requirements of an end-use EERS requirement in a reference case
projection, beginning at a specified date. These considerations are
addressed in more detail in Section VIII.F.7. below and in the
Projecting CO2 Emission Performance in State Plans TSD.
3. Incorporating RE and Demand-Side EE Measures Under a Rate-Based
Approach
We are proposing that RE and demand-side EE measures may be
incorporated into a rate-based approach through an adjustment or
tradable credit system applied to an EGU's reported CO2
emission rate.\294\ Under such a process, measures that avoid EGU
CO2 emissions from affected EGUs, such as quantified and
verified end-use energy savings and renewable energy generation, could
be credited toward a demonstrated CO2 emission rate for EGU
compliance purposes or used by the state to administratively adjust the
average CO2 emission rate of affected EGUs when
demonstrating achievement of the required rate-based emission
performance level in a state plan.
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\294\ We are also proposing that RE and demand-side EE measures
could be used under a mass-based portfolio approach in an approvable
state plan. However, the focus of this section is limited to
application of such measures under a rate-based approach.
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Under this approach, affected EGUs \295\ could comply with a
CO2 emission rate limit in part through the use of credits
for actions that avoid CO2 emissions from affected EGUs. If
a state is implementing a portfolio approach, then the state could
administratively adjust the average CO2 emission rate of
affected EGUs through a similar process, provided that the
CO2-avoiding measures are enforceable elements of the state
plan.
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\295\ This could include an individual affected EGU or group of
affected EGUs if a rate-based averaging or trading approach is used.
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We are seeking comment on different approaches for providing such
crediting or administrative adjustment of EGU CO2 emission
rates, which are elaborated further in the State Plan Considerations
TSD.
Credits or adjustment might represent avoided MWh of electric
generation or avoided tons of CO2 emissions. The approach
chosen could have significant implications for the amount of adjustment
or credit provided for RE and demand-side EE measures. If adjustment or
credits represent avoided MWh, they would be added to the denominator
when determining an adjusted lb CO2/MWh emission rate. If
adjustment or credits represent avoided CO2 emissions, they
would be subtracted from the numerator when determining an adjusted lb
CO2/MWh emission rate.
A MWh crediting or adjustment approach implicitly assumes that the
avoided CO2 emissions come directly from the particular
affected EGU (or group of EGUs) to which the credits are
[[Page 34920]]
applied. It assumes, in effect, that an additional emission-free MWh is
being generated by that respective EGU, and that the RE or demand-side
EE measure reduces CO2 emissions from that individual EGU or
group of EGUs.\296\ In practice, the average or marginal CO2
emission rate in the power pool or identified region--representing the
avoided CO2 emissions from the generating sources being
displaced by a MWh of energy savings or a MWh of renewable energy
generation--could differ significantly from the calculated avoided
CO2 emissions derived by adjusting the MWh output of an
affected EGU.
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\296\ As a result, the assumed avoided CO2 emissions
from an individual MWh of energy savings or MWh of generation from
renewable energy will differ based on the reported CO2
emission rate of the individual EGU to which the MWh is applied as
an adjustment to its MWh output.
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An alternative approach is to provide an adjustment based on the
estimated CO2 emissions that are avoided from the power pool
or identified region as a result of RE and demand-side EE measures.
This approach implicitly assumes that the avoided CO2
emissions come from the electric power pool or other identified region
as a whole, rather than an individual EGU. The avoided CO2
emissions are determined based on the MWh saved or generated,
multiplied by a CO2 emission rate for the power pool or
region. This CO2 emission rate could be based on the average
or marginal emission rate in the power pool or region, or could be
based on the emission rate that represents the required rate-based
emission performance level in the plan. We invite comment on each of
these possible approaches.
In addition, because some of the CO2 emissions avoided
through RE and demand-side EE measures may be from non-affected EGUs,
we are seeking comment on how this might be addressed in a state plan,
whether when adjusting or crediting CO2 emission rates of
affected EGUs based on the effects of RE and demand-side EE measures or
otherwise. How these dynamics might be addressed, both in projections
of plan performance and in actual demonstration of performance achieved
under a plan, is further discussed in the State Plan Considerations
TSD.
4. Quantification, Monitoring, and Verification of RE and Demand-Side
EE Measures
A key consideration for state plans is the process and requirements
under a state plan for quantifying, monitoring, and verifying the
effect of RE and demand-side EE measures that result in electricity
generation or electricity savings.
The EPA is proposing that a state plan that includes enforceable RE
and demand-side EE measures must include an evaluation, measurement,
and verification (EM&V) plan that explains how the effect of these
measures will be determined in the course of plan implementation. An
EM&V plan will specify the analytic methods, assumptions, and data
sources that the state will employ during the state plan performance
periods to determine the energy savings and energy generation related
to RE and demand-side EE measures. An EM&V plan would be subject to EPA
approval as part of a state plan. As discussed below, the EPA intends
to develop guidance on acceptable EM&V methods that could be
incorporated in an approvable EM&V plan that is included as part of an
approvable state plan.
Utilities and states have conducted ongoing EM&V of demand-side EE
and RE measures and programs for several decades. Current practice with
EM&V for RE and demand-side EE programs in the U.S. is primarily
defined by state public utility commission (PUC) requirements for
customer-funded energy efficiency and renewable energy programs, as
well as related compliance and reporting requirements for EERS and
renewable portfolio standards (RPS).
The level of PUC oversight of demand-side EE programs varies from
state to state, but this oversight process has generated the majority
of the industry guidance and protocols for documenting energy savings
from EE programs. Typically, impact evaluation reports are responsive
to requirements established by PUCs and submitted (usually annually)
for PUC review, approval, and use in resource planning and performance
assessment. These PUC requirements generally rely upon a well-defined
set of industry-standard practices and procedures. In states with the
most experience implementing and overseeing demand-side EE programs,
this typically includes: Use of one or more industry-standard EM&V
protocols or guidelines; use of ``deemed savings values,'' \297\ where
appropriate, for well-understood demand-side EE measures; consideration
of local factors, such as climate, building type, and occupancy;
involvement of stakeholders and solicitation of expert advice regarding
EM&V processes and resulting energy savings impacts; conduct of EM&V
activities (e.g., direct equipment measurements, application of deemed
savings, and reporting of impacts) on a regular basis; and provision of
interim and annual reporting of achieved energy savings.
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\297\ Deemed savings are measure-specific stipulated values
based on historical and verified data. Unlike other EM&V approaches,
deemed savings approaches involve limited or no measurement
activities, and are therefore a common and relatively low-cost
strategy for documenting energy savings.
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Despite this well-defined and generally accepted set of industry
practices, many states with energy efficiency programs use different
input values and assumptions in applying these practices (e.g., net
versus gross savings,\298\ run-time of equipment, measure lifetime).
This can result in significant differences in claimed energy savings
values for similar energy efficiency measures between states and
utilities, even when the same measure type is installed under otherwise
identical circumstances. In response to a growing awareness of this
lack of cross-state comparability, policy makers, regulatory agencies,
and other stakeholders are increasingly advocating for the use of
common evaluation approaches across jurisdictions. A number of states
and utilities in different regions of the country are already working
to develop such common approaches.
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\298\ Gross savings are the change in energy use (MWh) and
demand (MW) that results directly from program-related actions taken
by program participants, regardless of why they participated in a
program. Net savings refer to the change in energy use and demand
that is directly attributable to a particular energy efficiency
program.
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For RE measures and programs, EM&V employed by states and utilities
commonly relies upon a set of standard practices and procedures, such
as the use of revenue-quality meters for quantifying RE generation. As
a result, existing state and utility requirements and processes for
quantification, monitoring, and verification of RE programs and
measures generally provide a solid foundation for minimum requirements
or guidance established by the EPA for state plans.
For both RE and demand-side EE measures included in state plans,
additional information and reporting may be necessary to accurately
quantify the avoided CO2 emissions associated with these
measures, such as information on the location and the hourly, daily, or
seasonal basis of renewable energy generation or energy savings.
Current state and utility EM&V approaches for RE and demand-side EE
programs and mandates are discussed in more detail in the State Plan
[[Page 34921]]
Considerations TSD. We are seeking comment on the suitability of these
approaches in the context of an approvable state plan, and on whether
harmonization of state approaches, or supplemental actions and
procedures, should be required in an approvable state plan. In
particular, we intend to establish guidance for acceptable
quantification, monitoring, and verification of RE and demand-side EE
measures for an approvable EM&V plan, and are seeking comment on
critical features of such guidance, including scope, applicability, and
minimum criteria.\299\ We are also seeking comment on the appropriate
basis for and technical resources used to establish such guidance,
including consideration of existing state and utility protocols, as
well as existing international, national, and regional consensus
standards or protocols.\300\ The EPA's goal in developing such guidance
is to assure that it is consistent with industry-standard EM&V
approaches for both RE and demand-side EE measures and programs,
leverages the EM&V resources and infrastructure already in place in
many states, and strikes a reasonable balance between EM&V costs,
rigor, and the value of resulting information, while considering the
specific use of such information in assessing avoided CO2
emissions from affected EGUs.
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\299\ Section V.A.4 of the State Plan Considerations TSD
includes a detailed description of these EM&V parameters.
\300\ A list of these protocols is provided in Section V.A.3.1
of the State Plan Considerations TSD.
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In developing guidance, the agency does not intend to limit the
types of RE and demand-side EE measures and programs that can be
included in a state plan, provided that supporting EM&V is rigorous,
complete, and consistent with the EPA's guidance. This approach
recognizes differences among RE and demand-side EE programs and
measures with respect to implementation history and experience,
existence of applicable EM&V protocols and methods, and the nature and
type of program oversight (e.g., whether or not a program is subject to
PUC oversight). The EPA is requesting comment on the merits of this
approach, including whether such guidance should identify types of RE
and demand-side EE measures and programs for which evaluation of
results is relatively straightforward and which are appropriate for
inclusion in a state plan. Such approaches might be subject to
streamlined review of EM&V protocols included in an approvable state
plan, provided that such protocols are applied in accordance with
industry best practices. For example, many utilities have implemented a
similar core set of RE and demand-side EE measures and programs for
utility customers. For these types of measures and programs, a
substantial base of experience has been established nationally for the
evaluation of measure and program outcomes. Other types of measures and
programs, such as those that seek to alter consumer and building
occupant behavior might pose quantification and verification
challenges. Still other types of measures, such as state energy-
efficient appliance standards and building codes, have not typically
been subject to similar evaluation of energy savings results. These
types of approaches might have substantial impacts, and the EPA does
not want to discourage their implementation in state plans, but they
might require development of appropriate quantification, monitoring,
and verification protocols. The EPA and its federal partners intend to
discuss the development of appropriate EM&V protocols for such measures
with states in the coming years.
As an alternative to the EPA's proposed approach of allowing a
broad range of RE and demand-side EE measures and programs to be
included in state plans, provided that supporting EM&V documentation
meets applicable minimum requirements, the EPA is requesting comment on
whether guidance should limit consideration to certain well-established
programs, such as those characterized in Section V.A.4.2.1 of the State
Plan Considerations TSD.
5. Reporting and Recordkeeping for Affected Entities Implementing RE
and Demand-Side EE Measures
If a state plan incorporates RE and demand-side EE measures under a
rate-based approach or implements a mass-based portfolio approach with
such measures, reporting and recordkeeping requirements for an
approvable plan would differ from those applicable to an affected EGU.
For example, these requirements may include compliance reporting by an
electric distribution utility subject to an EERS or RPS. They may also
include reporting by a vertically integrated utility implementing an
approved integrated resource plan. In the latter instance, the utility
might also be the owner and operator of affected EGUs, but additional
reporting of quantified effects of RE and demand-side EE measures under
the utility plan would be necessary to demonstrate emission performance
under the state plan. In other instances, a state agency or entity or a
private or public third-party entity might be implementing programs and
measures that support the deployment of end-use energy efficiency and
clean energy technologies that are incorporated into a state plan. In
each of these instances, reporting of program compliance or program
outcomes is a necessary part of an approvable plan to demonstrate
emission performance under the plan.
Examples of potential reporting obligations for affected entities
implementing RE and demand-side EE measures in an approvable state plan
are provided in the State Plan Considerations TSD. We are seeking
comment on the examples and suitability of potential approaches
described in the TSD and any other appropriate reporting and
recordkeeping requirements for affected entities beyond affected EGUs.
6. Treatment of Interstate Effects
The electricity system and wholesale electricity markets are
interstate in nature. EGUs in one state provide electricity to
customers in neighboring states. Power companies often own EGUs in more
than one state and manage them as a system. EGUs are dispatched both
within and across state borders.
Similarly, programs and measures in a state plan, such as RE and
demand-side EE measures, may affect the performance of the
interconnected electricity system beyond a state border. In addition,
many state programs allow for actions in neighboring states to meet the
in-state requirement or explicitly address CO2 emissions in
neighboring states. For example, many state renewable portfolio
standards allow for generation by qualifying renewable energy sources
in other states to count toward meeting the state portfolio
requirement. Some states also apply CO2 emission
requirements related to the generation of power purchased by regulated
utilities, including power imported from out of state.
The EPA recognizes the complexity of accounting for interstate
effects associated with measures in a state plan in a consistent
manner, to allow states to take into account the CO2
emission reductions resulting from these programs while minimizing the
likelihood of double counting. We also realize that interstate effects
on CO2 emissions from affected EGUs could be attributed in
different manners in the context of an approvable state plan. The EPA
is seeking comment on the options summarized below, as well as
alternatives. These options and alternatives, and how they might apply
to both projections of plan performance
[[Page 34922]]
and reporting of achieved plan performance, are addressed in the State
Plan Considerations TSD.
The EPA is proposing that, for demand-side EE measures, consistent
with the approach that the EPA used in determining the BSER, a state
could take into account in its plan only those CO2 emission
reductions occurring (or projected to occur) in the state that result
from demand-side EE measures implemented in the state. The agency is
also proposing that, for states that participate in multi-state plans,
the participating states would have the flexibility to distribute the
CO2 emission reductions among states in the multi-state
area, as long as the total CO2 emission reductions claimed
are equal to the total of each state's in-state emissions reductions
that result from demand-side EE measures implemented in those states.
We are also proposing that states could jointly demonstrate
CO2 emission performance by affected EGUs through a multi-
state plan in a contiguous electric grid region, in which case
attribution of emission reductions from demand-side EE measures would
not be necessary. We also request comment on whether a state should be
able to take credit for emission reductions out of state due to in-
state EE measures if the state can demonstrate that the reductions will
not be double-counted when the relevant states report on their achieved
plan performance, and what such a demonstration should entail. We
request comment on these and other approaches for taking into account
CO2 emission reductions from demand-side EE measures in
state plans.
The EPA is proposing that, for renewable energy measures,
consistent with existing state RPS policies, a state could take into
account all of the CO2 emission reductions from renewable
energy measures implemented by the state, whether they occur in the
state or in other states. This proposed approach for RE acknowledges
the existence of renewable energy certificates (REC) that allow for
interstate trading of RE attributes and the fact that a given state's
RPS requirements often allow for the use of qualifying RE located in
another state to be used to comply with that state's RPS.
The EPA is also seeking comment on how to avoid double counting
emission reductions using this proposed approach. The agency is also
proposing that states participating in multi-state plans could
distribute the CO2 emission reductions among states in the
multi-state area, as long as the total CO2 emission
reductions claimed are equal to the total of each state's in-state
emission reductions from RE measures. We also request comment on the
option of allowing a state to take into account only those
CO2 emission reductions occurring in its state. We are also
proposing that states could jointly demonstrate CO2 emission
performance by affected EGUs through a multi-state plan in a contiguous
electric grid region, in which case attribution among states of
emission reductions from renewable energy measures would not be
necessary. We also request comment on whether a state should be able to
take credit for emission reductions out of state due to renewable
energy measures if the state can demonstrate that the reductions will
not be double-counted when the relevant states report on their achieved
plan performance, and on what such a demonstration should entail. We
request comment on these and other approaches for taking into account
CO2 emission reductions from renewable energy measures.
7. Projecting Emission Performance
As proposed, an approvable state plan will include a projection of
CO2 emission performance by affected EGUs under the plan. In
addition, a state plan that is using a mass-based goal in determining
the required level of emission performance under the plan will include
a translation of the rate-based emission goal in the emission
guidelines to a mass-based goal. This translation will involve a
projection of CO2 emissions from affected EGUs during the
initial 2020-2029 plan performance period and in 2030, under a scenario
that assumes the rate-based goal in the emission guidelines is met.
The EPA is striving to find a balance between providing state
implementation flexibility and ensuring that the emission performance
required by CAA section 111(d) is properly defined in state plans and
that plan performance projections have technical integrity. Each state
plan must include a projection of CO2 emission performance
from affected EGUs during the multi-year plan period that will result
from implementation of the plan. Depending on the type of plan
approach, this will include either a projection of the average
CO2 emission rate achieved by affected EGUs or total
CO2 emissions from affected EGUs.
The credibility of state plans under CAA section 111(d) will depend
in large part on ensuring credible and consistent emission performance
projections in state plans. Therefore, the use of appropriate methods,
tools and assumptions for such projections is critical.
Considerations for projecting emission performance under a state
plan will differ depending on the type of plan. This includes
differences in how inputs to projections are derived; how projections
are conducted, including tools, methods and assumptions; and how
aspects of a plan are represented in these projections.
In general, any material component of a state requirement or
program included in a state plan that could affect emission performance
by affected EGUs should be accurately represented in emission
projections included in the state plan.
For example, mass-based emission budget trading programs include a
number of compliance flexibility mechanisms that might impact emission
performance achieved by affected EGUs subject to these programs. These
include multi-year compliance periods; the ability to bank allowances
issued in a previous compliance period for use in a subsequent
compliance period; the use of out-of-sector project-based emission
offsets; and cost-containment allowance reserves that make additional
allowances available to the market if pre-established allowance price
thresholds are achieved. As a result, annual emissions from affected
sources subject to an emission budget trading program often differ from
the established annual emission budget for affected sources. In
addition, these programs may be multi-sector in nature, regulating
emissions for source categories in addition to EGUs. As a result,
emission projections in state plans will need to accurately account for
and represent these compliance flexibilities, as well as the scope of
affected sources if they are broader than EGUs affected under CAA
section 111(d). Similarly, other types of state programs, such as RPS,
may include flexibility mechanisms or other provisions, such as
alternative compliance payment mechanisms, banking, and limits on total
ratepayer impact, that affect the ultimate amount of electricity
generation required under the portfolio standard. These considerations
for different types of state programs are discussed in more detail in
the Projecting EGU CO2 Emission Performance in State Plans
TSD.
In general, as with projections used to determine a mass-based
goal, projections of emission performance under a state plan could be
conducted using historical data and parameters for estimating the
future impact of individual state programs and measures. Alternatively,
a projection could include modeling, such as use of a capacity planning
and dispatch
[[Page 34923]]
model.\301\ This latter approach would be able to capture dynamic
interactions within the electricity sector, based on system operation
and market forces, including interactions among state programs and
measures and the dynamics of market-based measures.
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\301\ In many cases, this approach will also require the
development of parameters for estimating the future effect of
individual state programs and measures, for use as input assumptions
for modeling.
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These considerations, and considerations for projecting emission
performance under different types of state plan approaches, are
discussed in detail in the Projecting EGU CO2 Emission
Performance in State Plans TSD.
We are seeking comment on the considerations discussed in this TSD,
including options presented for how projections might be conducted in
an approvable state plan, and how different types of state plan
approaches are represented in these projections. We are seeking further
comment on whether the EPA should develop guidance that describes
acceptable projection approaches, tools, and methods for use in an
approvable plan, as well as providing technical resources for
conducting projections.
The ISO/RTO Council, an organization of electric grid operators,
has suggested that ISOs and RTOs could provide analytic support to help
states develop and implement their plans. The ISOs and RTOs have the
capability to model the system-wide effects of individual state plans.
Providing assistance in this way, they felt, would allow states with
borders that fall within an ISO or RTO footprint to assess the system-
wide impacts of potential state plan approaches. In addition, as the
state implements its plan, ISO/RTO analytic support would allow the
state to monitor the effects of its plan on the regional electricity
system. ISO/RTO analytic capability could help states assure that their
plans are consistent with region-wide system reliability. The ISO/RTO
Council suggested that the EPA ask states to consult with the
applicable ISO/RTO in developing their state plans. The EPA agrees with
this suggestion and encourages states with borders that fall within one
or more ISO or RTO footprints to consult with the relevant ISOs/RTOs.
8. Potential Emission Reduction Measures Not Used To Set Proposed Goals
States may include measures in their plans beyond those that the
EPA included in its determination of the BSER. In general, any measures
that meet the proposed criteria for approvable state plans could be
employed in a state plan. Beyond that, under a mass-based approach, any
measure that reduces affected EGU emissions--even if not included in
the state plan--will, if implemented during a plan performance period,
help to achieve actual emissions performance that meets the required
level.
Beyond the types of state plan measures already discussed in this
section of the preamble, the agency has identified a number of other
measures that could also lead to CO2 emission reductions
from EGUs. These include, for example, electricity transmission and
distribution efficiency improvements, retrofitting affected EGUs with
partial CCS, the use of biomass-derived fuels at affected EGUs, and use
of new NGCC units. Although the emission reduction methods discussed in
this section are not proposed to be part of the BSER, the agency
anticipates that some states may be interested in using these
approaches in their state plans. The agency solicits comment on whether
these measures are appropriate to include in a state plan to achieve
CO2 emission reductions from affected EGUs. In addition to
the specific requests for comment related to specific technologies
below, we also request comment on other measures that would be
appropriate. In addition, we request comment on whether the EPA should
provide specific guidance on inclusion of these measures in a state
plan.
In addition, technological advances and innovations in energy and
pollution control technologies will continue over time. The agency is
aware that as new technologies become available or as costs of a
technology drop because of technical advances, states may wish to
include measures in their state plans that make use of those
technologies.
To be more specific, there are multiple potential measures that can
be taken at an EGU beyond heat rate improvements that will reduce
CO2 emissions. Some examples are: Including co-firing of
less CO2 intensive fuels such as natural gas, retrofit of
partial CCS and use of integrated renewable technology (i.e. meeting
some of the steam load in a steam turbine from a fossil unit and part
of the steam load from a concentrating solar installation), and
improving heat rates of oil- and gas-fired generating units. Co-firing
of natural gas and the use of CCS could be incorporated into a state
plan demonstration of emission performance as a reduction in the
emission rate at an affected EGU in exactly the same way that heat rate
reductions could be quantified. In the case of an integrated renewable
and fossil unit, reductions could either be quantified as a reduction
in rate, or the renewable component could be quantified in the same way
other renewable reductions are quantified in the state plan.
In addition to the nuclear generation taken into account in the
state goals analysis, any additional new nuclear generating units or
uprating of existing nuclear units, relative to a baseline of capacity
as of the date of proposal of the emission guidelines, could be a
component of state plans. This baseline would be consistent with the
proposed approach for treatment of existing state programs. The agency
requests comment on alternative nuclear capacity baselines, including
whether the date for recognizing additional non-BSER nuclear capacity
should be the end of the base year used in the BSER analysis of
potential nuclear capacity (i.e., 2012). In general, when considering
nuclear generation in a state plan, states may wish to consider the
impacts that different types of policies may have on different types of
zero-emitting generation. Under a capped approach which does not
provide any ``crediting'' for zero-emitting generation, the impact on
all zero-emitting units should be the same. In a rate based approach
that credited zero or low-emitting generation, the crediting mechanism
used could result in different economic impacts on different types of
zero- or low-emitting generation.
Another way that a state plan could reduce utilization and
emissions from affected existing EGUs would be through construction of
new NGCC--that is, NGCC on which construction commences after the date
of proposal or finalization of CAA section 111(b) standards applicable
to that source. (The agency's CAA section 111(d) proposal does not
include new NGCC as a component of the BSER, but requests comment on
that question in Section VI of this preamble.) Under a mass-based plan
where an emission limit on affected EGUs would assure achievement of
the required level of emission performance in the state plan, any
emission reductions at affected EGUs resulting from substitution of new
NGCC generation for higher-emitting generation by existing affected
EGUs would automatically be reflected in mass emission reductions from
affected EGUs. A state would not need to include enforceable provisions
for new NGCC in its plan, under such an approach. However, under a
mass-based portfolio approach, enforceable measures in a state plan
might include
[[Page 34924]]
construction of new NGCC to replace one or more affected EGUs, perhaps
as part of a utility IRP and related PUC orders. Again, the effects of
new NGCC generation would be realized in reduced mass emissions from
affected EGUs.
The agency requests comment on how emissions changes under a rate-
based plan resulting from substitution of generation by new NGCC for
generation by affected EGUs should be calculated toward a required
emission performance level for affected EGUs. Specifically, considering
the legal structure of CAA section 111(d), should the calculation
consider only the emission reductions at affected EGUs, or should the
calculation also consider the new emissions added by the new NGCC unit,
which is not an affected unit under section 111(d)? Should the
emissions from a new NGCC included as an enforceable measure in a mass-
based state plan (e.g., in a plan using a portfolio approach) also be
considered?
Similar to zero-emitting generation, states may also want to
consider whether the policy design they choose sends similar or
different price signals to new and existing NGCC. For instance, under a
mass based program, if new NGCCs were not included, their costs would
be less than the cost of an existing NGCC unit.
In respect to new fossil fuel-fired EGUs, the agency also requests
comment on the concept of providing credit toward a state's required
CAA section 111(d) performance level for emission performance at new
CAA section 111(b) affected units that, through application of CCS, is
superior to the proposed standards of performance for new EGUs. Because
the EPA proposed to find that the BSER for new fossil fuel-fired
boilers and IGCC units is only a partial application of CCS, we
recognize that there is the potential for such units, if constructed,
to obtain additional emission reductions by increasing the level of CCS
and outperforming the proposed performance standards. In some cases
these incremental emission reductions may represent a cost effective
abatement option for states and would provide an incentive for the
deployment and advancement of CCS. We invite comment on whether
incremental emission reductions from new fossil fuel-fired boilers and
IGCC units with CCS, based on exceeding the CAA section 111(b)
performance standards for such units, should be allowed as a compliance
option to help meet the emission performance level required under a CAA
section 111(d) state plan.
Similarly, while the EPA did not propose to establish standards of
performance for new NGCC units based on CCS under CAA section 111(b),
we recognize that if a new NGCC unit were to be constructed with a CCS
system, it could achieve a lower CO2 emission rate than
required by the proposed standards of performance for new NGCC units.
We invite comment on whether incremental emission reductions from new
NGCC units that outperform the performance standards for such units
under CAA section 111(b) based on the use of CCS should be allowed as a
compliance option to help meet the emission performance level required
under a CAA section 111(d) state plan.
Building block 4 focuses on improving end-use energy efficiency.
Another way to reduce the utilization of, and CO2 emissions
from, affected EGUs is through electricity transmission and
distribution upgrades that reduce electricity losses during the
delivery of electricity to end users. Just as end-use energy efficiency
can reduce mass emissions from affected EGUs, so can transmission
upgrades.
In addition, electricity storage technologies have the potential to
enhance emission performance by reducing the need for fossil fuel-fired
EGUs to provide generation during periods when intermittent wind and
solar generation are unavailable due to natural conditions. States may
wish to consider this possibility as they consider options for design
of their plans.
The agency requests comment on whether industrial combined heat and
power approaches warrant consideration as a potential way to avoid
affected EGU emissions, and whether the answer depends on circumstances
that depend on the type of CHP in question.
Many of the decisions that states will make while developing
compliance approaches are fundamentally state decisions that will have
impacts on issues important to the state, including cost to consumers
and broader energy policy goals, but will not impact overall emission
performance. Some decisions, however, may impact emission performance
and exemplify the kinds of decisions and approaches states may be
interested in pursuing. In light of the broad latitude that the EPA is
seeking to afford the states, including latitude to adopt measures such
as those discussed in this subsection, the EPA intends to make
additional technical resources available and consider developing
guidance for states, should they need such support in exploring and
adopting these options. The EPA, in addition, requests comment on
whether there are still other areas beyond those discussed above for
which it would be useful for the EPA to provide guidance.
Through President Obama's Climate Action Plan, the Administration
is working to identify new approaches to protect and restore our
forests, as well as other critical landscapes including grasslands and
wetlands, in the face of a changing climate. Sustainable forestry and
agriculture can improve resiliency to climate change, be part of a
national strategy to reduce dependence on fossil fuels, and contribute
to climate change mitigation by acting as a ``sink'' for carbon. The
plant growth associated with producing many of the biomass-derived
fuels can, to varying degrees for different biomass feedstocks,
sequester carbon from the atmosphere. For example, America's forests
currently play a critical role in addressing carbon pollution, removing
nearly 12 percent of total U.S. greenhouse gas emissions each year. As
a result, broadly speaking, burning biomass-derived fuels for energy
recovery can yield climate benefits as compared to burning conventional
fossil fuels.
Many states have recognized the importance of forests and other
lands for climate resilience and mitigation and have developed a
variety of different sustainable forestry policies, renewable energy
incentives and standards and greenhouse gas accounting procedures.
Because of the positive attributes of certain biomass-derived fuels,
the EPA also recognizes that biomass-derived fuels can play an
important role in CO2 emission reduction strategies. We
anticipate that states likely will consider biomass-derived fuels in
energy production as a way to mitigate the CO2 emissions
attributed to the energy sector and include them as part of their plans
to meet the emission reduction requirements of this rule, and we think
it is important to define a clear path for states to do so.
To better understand the impacts of using different types of
biomass-derived fuels, the EPA is assessing the use of biomass
feedstocks for energy recovery by stationary sources and has developed
a draft accounting framework that the EPA's Science Advisory Board
(SAB) has reviewed. The draft framework concluded that while biomass
and other biogenic feedstocks have the potential to reduce the overall
level of CO2 emissions resulting from electricity
generation, the contribution of biomass-derived fuels to atmospheric
CO2 is sensitive to the type of biomass feedstock used, and
the way in which the feedstock is grown, processed, and ultimately
combusted as a fuel for energy production. The SAB in its review
similarly found that there are
[[Page 34925]]
circumstances in which biomass is grown, harvested and combusted in a
carbon neutral fashion but commented that additional considerations are
warranted.
The EPA is in the process of revising the draft framework and
considering next steps, taking into account both the comments provided
by the SAB and feedback from stakeholders. The EPA's biogenic
CO2 accounting framework is expected to provide important
information regarding the scientific basis for assessing these biomass-
derived fuels and their net atmospheric contribution of CO2
related to the growth, harvest and use of these fuels. This information
should assist both states and the EPA in assessing the impact of the
use of biomass fuels in reaching emission reduction goals in the energy
sector under state plans to comply with the requirements in the
emission guidelines.
9. Consideration of a Facility's ``Remaining Useful Life'' in Applying
Standards of Performance
In this section, the EPA discusses the relevance to this rule of
the EPA regulations implementing the CAA section 111(d)(1) provision
``permit[ing] the State in applying a standard of performance to any
particular source under a [111(d)] plan . . . to take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies.''
For the reasons discussed below, the EPA is proposing that, in this
case, the flexibility provided in the state plan development process
adequately allows for consideration of the remaining useful life of the
affected facilities and other source-specific factors and, therefore,
that separate application of the remaining useful life provision by
states in the course of developing and implementing their CAA section
111(d) plans is unnecessary. The agency is requesting comment on its
analysis below of the implications of the EPA's existing regulations
interpreting ``useful life'' and ``other factors'' for purposes of this
rulemaking.\302\ The agency also requests comment on whether it would
be desirable to include in regulatory text any aspects of this preamble
discussion about how the provisions in the existing implementing
regulations concerning source-specific factors relate to this emission
guideline.
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\302\ The agency is not reopening or considering changes to this
provision of the implementing regulations.
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This section addresses the legal background concerning facility-
specific considerations and the implications for implementation of
these emission guidelines, including state emissions performance goals.
a. Legal Background
The EPA's 1975 implementing regulations \303\ address remaining
useful life and other facility-specific factors that might affect
requirements for an existing source under section 111(d). Those
regulations provide that for a pollutant such as GHGs, which have been
found to endanger public health, standards of performance in state
plans must be as stringent as the EPA's emission guidelines. Deviation
from the standard might be appropriate where the state demonstrates
with respect to a specific facility (or class of facilities):
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\303\ 40 CFR 60.24(f).
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(1) Unreasonable cost of control resulting from plant age,
location, or basic process design;
(2) Physical impossibility of installing necessary control
equipment; or
(3) Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable.
The reference to ``[u]nreasonable cost of control resulting from
plant age'' implements the statutory provision on remaining useful
life. The language concerning plant location, basic process design,
physical impossibility of installing controls, and ``other factors''
addresses facility-specific issues other than remaining useful life
that the EPA determined that in some circumstances can affect the
reasonableness of a control measure for a particular existing source.
This regulatory provision provides the EPA's default structure for
implementing the remaining useful life provision of CAA section 111(d).
The opening clause, however, which provides that this provision is
applicable ``unless otherwise specified in the applicable subpart''
makes clear that this structure may not be appropriate in each case and
that the EPA has discretion to alter the extent to which states may
authorize relaxations to standards of performance that would otherwise
apply to a particular source or source category, if appropriate under
the circumstances of the specific source category and proposed
guidelines.
b. Implications for Implementation of These Emission Guidelines
In general, the EPA notes that the implementing regulation
provisions for remaining useful life and other facility-specific
factors are relevant for emission guidelines in which the EPA specifies
a presumptive standard of performance that must be fully and directly
implemented by each individual existing source within a specified
source category. Such guidelines are much more like a CAA section
111(b) standard in their form. For example, the EPA emission guidelines
for sulfuric acid plants, phosphate fertilizer plants, primary aluminum
plants, and Kraft pulp plants specify emission limits for sources.\304\
In the case of such emission guidelines, some individual sources, by
virtue of their age or other unique circumstances, may warrant special
accommodation.
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\304\ See ``Phosphate Fertilizer Plants; Final Guideline
Document Availability,'' 42 FR 12,022 (Mar. 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55,796 (Oct. 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29,828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26,294 (Apr. 17, 1980);
``Standards of Performance for New Stationary Sources and Guidelines
for Control of Existing Sources: Municipal Solid Waste Landfills,
Final Rule,'' 61 FR 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------
In these proposed guidelines for state plans to limit
CO2 from affected EGUs, the agency does not take that
approach. Instead, the EPA is proposing to establish state emission
performance goals for the collective group of affected EGUs in a state,
leaving to each state the design of the specific requirements that fall
on each affected EGU. Due to the inherent flexibility in the EPA's
approach to establishing the state-specific goals, and the flexibility
provided to states in developing approvable CAA section 111(d) plans to
achieve those goals, the EPA's guidelines contain no emission standards
that the state must apply directly to a specific EGU; therefore, no
relief for individual facilities would be needed.
Rather, because of the flexibility for states to design their own
standards, the states have the ability to address the issues involved
with ``remaining useful life'' and ``other factors'' in the initial
design of those standards, which would occur within the framework of
the CAA section 111(d) plan development process. States are free to
specify requirements for individual EGUs that are appropriate
considering remaining useful life and other facility-specific factors.
Therefore, to the extent that a performance standard that a state
may wish to adopt for affected EGUs raises facility-specific issues,
the state is free to make adjustments to a particular facility's
requirements on facility-specific grounds, so long as any such
adjustments are reflected (along with
[[Page 34926]]
any necessary compensating emission reductions), as part of the state's
CAA section 111(d) plan submission. The agency requests comment on its
interpretation.
c. Relationship to State Emission Performance Goals and Timing of
Achievement
The EPA also believes that, because of the way the state-specific
goals have been developed in these proposed guidelines, remaining
useful life and other facility-specific considerations should not
affect the determination of a state's rate-based or mass-based emission
performance goal or the state's obligation to develop and submit an
approvable CAA section 111(d) plan that achieves that goal by the
applicable deadline.
Under the proposed guideline, states would have the flexibility to
adopt a state plan that relies on emission-reducing requirements that
do not require affected EGUs with a short remaining useful life to make
major capital expenditures \305\ or incur unreasonable costs. Indeed,
the EPA's proposal would provide states with broad flexibility
regarding ways to improve emission performance through utilizing the
emissions reduction methods represented by the four ``building
blocks.''
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\305\ The agency requests comment on whether there are
circumstances other than a major capital investment that could lead
to a prospective state plan imposing unreasonable costs considering
a facility's remaining useful life. Where annual costs predominate
and/or capital costs do not constitute a major expense, the EPA
believes that the remaining useful life of an affected EGU will not
significantly affect its annualized cost of control and therefore
should not be a factor in determining control requirements for the
EGU.
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We also note that a state is not required to achieve the same level
of emission reductions with respect to any one building block as
assumed in the EPA's BSER analysis. If a state prefers not to attempt
to achieve the level of performance estimated by the EPA for a
particular building block, it can compensate through over-achievement
in another one, or employ other compliance approaches not factored into
the state-specific goal at all. The EPA has estimated reasonable rather
than maximum possible implementation levels for each building block in
order to establish overall state goals that are achievable/while
allowing states to take advantage of the flexibility to pursue some
building blocks more aggressively, and others less aggressively, than
is reflected in the goal computations, according to each state's needs
and preferences.
Of the four building blocks considered by the EPA in developing
state goals, only the first block, heat rate improvements, involves
capital investments at the affected EGUs which, if mandated by a state
rule, might give rise to remaining useful life considerations at a
particular facility. The other building blocks--re-dispatch among
affected sources, addition of new generating capacity, and improvement
in end-use energy efficiency--do not generally involve capital
investments by the owner/operator at an affected EGU.
In the case of heat rate improvements at affected EGUs, states can
choose whether to require a greater or lesser degree of heat rate
improvement than the 6 percent improvement assumed in the EPA's
proposed BSER determination, either because of the remaining useful
life of one or more EGUs, other source-specific factors that the state
deemed appropriate to consider, or any other relevant reasons. The
agency also notes that any capital expenditures would be much smaller
than capital expenditures required for example, for purchase and
installation of scrubbers to remove sulfur dioxide; a fleet-wide
average cost for heat rate improvements at coal-fired generating units
is $100/kW, compared with a typical SO2 scrubber cost of
$500/kw (costs vary with unit size).\306\ In addition, the proposed
guideline allows states to regulate affected EGUs through flexible
regulatory approaches that do not require affected EGUs to incur large
capital costs (e.g., averaging and trading programs). Under the EPA's
proposed approach--establishing state goals and providing states with
flexibility in plan design--states have flexibility to make exactly the
kind of judgments necessary to avoid requirements that would result in
stranded assets.
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\306\ Heat rate improvement methods and related capital costs
are discussed in the GHG Abatement Measures TSD; SO2
scrubber capital costs are from the documentation for the EPA's IPM
Base Case v5.13, Chapter 5, Table 5-3, available at http://www.epa.gov/powersectormodeling/BaseCasev513.html
---------------------------------------------------------------------------
Remaining useful life and other factors, because of their facility-
specific nature, are potentially relevant in determining requirements
that are directly applicable to affected EGUs. For all of the reasons
above, the agency believes that the issue of remaining useful life will
arise infrequently in the development of state plans to limit
CO2 emissions from affected existing EGUs. Even if relief is
due a particular facility, the state has an available toolbox of
emission reduction methods that it can use to develop a section 111(d)
plan that meets its emissions performance goal on time. The EPA
therefore proposes that the remaining useful life of affected EGUs, and
the other facility-specific factors identified in the existing
implementing regulations, should not be considered as a basis for
adjusting a state emission performance goal or for relieving a state of
its obligation to develop and submit an approvable plan that achieves
that goal on time. The agency solicits comment on this position.
10. Design, Equipment, Work Practice, or Operational standards
In this section, we discuss whether state plans may include design,
equipment, work practice, or operational standards.
CAA section 111(h)(1) authorizes the Administrator to promulgate
``a design, equipment, work practice, or operational standard, or
combination thereof,'' if in his or her judgment, ``it is not feasible
to prescribe or enforce a standard of performance.'' CAA section
111(h)(2) provides the circumstances under which prescribing or
enforcing a standard of performance is ``not feasible'': generally,
when the pollutant cannot be emitted through a conveyance designed to
emit or capture the pollutant, or when there is no practicable
measurement methodology for the particular class of sources. Other
provisions in section 111(h) further provide that a design, equipment,
work practice, or operational standard (i) must ``be promulgated in the
form of a standard of performance whenever it becomes feasible'' to do
so,\307\ and (ii) must ``be treated as a standard of performance'' for
purposes of, in general, the CAA.\308\
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\307\ CAA section 111(h)(4).
\308\ CAA section 111(h)(5).
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As noted above, CAA section 111(d) requires that state plans
``establish[] standards of performance'' as well as ``provide[] for the
implementation and enforcement of such standards of performance.'' CAA
section 111(d) is silent as to whether (i) states may include design,
equipment, work practice, or operational standards, or (ii) they may
include those types of standards, but only under the limited
circumstances described in section 111(h) (i.e., when it is ``not
feasible'' to prescribe or enforce a standard of performance).
Similarly, section 111(h) applies by its terms when the Administrator
is authorized to prescribe standards of performance (which would
include rulemaking under CAA section 111(b)), but is silent as to
whether it
[[Page 34927]]
applies to state plans under CAA section 111(d).\309\
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\309\ It should be noted that section 111(b)(5), which concerns
controls promulgated by the Administrator for new and modified
sources, does refer to section 111(h).
---------------------------------------------------------------------------
We invite consideration of the proper interpretation of CAA
sections 111(d) and (h), under either Chevron step 1 or step 2,
specifically: (i) Do the provisions of section 111(d) preclude state
plans from including ``design, equipment, work practice, or operational
standard[s]'' unless those things can be considered ``standards of
performance'' or as providing for the implementation and enforcement of
such standards? As a related matter, do the references to ``standard[s]
of performance'' in CAA section 111(h) indicate that design, equipment,
work practice, or operational standards cannot be considered
``standards of performance?'' (ii) Alternatively, are state plans
authorized to include those design, equipment, work practice, or
operational standards, but only under the limited circumstances
described in CAA section 111(h) relating to infeasibility? (iii) As
another alternative, are state plans authorized to include design,
equipment, work practice, or operational standards under all
circumstances, so that the limits of CAA section 111(h) do not apply?
Finally, to the extent there is legal uncertainty over whether, and
under what circumstances, state plans may include those standards,
should the EPA authorize state plans to include them, on the
understanding that if the Court invalidates the EPA's interpretation,
states would be required to revise their plans accordingly without
further rulemaking from the EPA?
11. Emissions Averaging and Trading
In this section, we discuss why CAA section 111(d) plans may
include standards of performance that authorize emissions averaging and
trading.
CAA section 111(d) authorizes state plans to include ``standards of
performance'' and measures that implement and enforce those standards
of performance. CAA section 111(a)(1) defines a ``standard of
performance'' as ``a standard for emissions of air pollutants which
reflects the degree of emission limitation achievable through the
application of the best system of emission reduction . . . adequately
demonstrated.'' CAA section 302 contains a set of definitions that
apply ``[w]hen used in [the Clean Air Act],'' including subsection (l),
which provides a separate definition of ``standard of performance'' as
``a requirement of continuous emission reduction. . .''
The EPA proposes that the definition of ``standard of performance''
is broad enough to incorporate emissions averaging and trading
provisions, including both emission rate programs, in which sources may
average or trade those rates, and mass emission limit programs, in
which sources may buy and sell mass emission allowances (and, under
certain circumstances, offsets).\310\ The term ``standard'' in the
phrase ``standard for emissions of air pollutants'' is not defined in
the CAA. As the Supreme Court noted in a CAA case, a ``standard'' is
simply ``that which `is established by authority, custom, or general
consent, as a model or example; criterion; test.' '' \311\ A tradable
emission rate or a tradable mass limit is a ``standard for emissions of
air pollutants'' because it establishes an emissions limit for a
source's air pollutants, and as a result, qualifies as a ``criterion''
or ``test'' for those air pollutants.
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\310\ Typically, in a mass emission limit trading program,
sources are required to obtain an allowance for each measure (e.g.,
ton) of air pollutant they emit. The acid rain program under Title
IV of the CAA is an example of this type of trading program.
\311\ Engine Mfrs. Ass'n v. South Coast Air Quality Mgmt. Dist.,
541 U.S. 246, 252-53 (2004) (quoting Webster's Second International
Dictionary, at 2455 (1945))
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Moreover, although there may be doubt that the definition of
``standard of performance'' in CAA section 302(l) applies to CAA
section 111(d) in light of the fact that the definition of the same
term in CAA section 111(a)(1) is more specific, even if the CAA section
302(l) definition does apply, an averaging or trading requirement
qualifies as a ``continuous emission reduction'' because, in the case
of a tradable emission rate, the rate is applicable at all times, and,
in the case of a tradable mass limit, the source is always under the
obligation that its emissions be covered by allowances.
It should be noted that the EPA has promulgated two other CAA
section 111(d) rulemakings that authorized state plans to include
emissions averaging or trading.\312\
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\312\ See ``Standards of Performance for New and Existing
Stationary Sources: Electric Utility Steam Generating Units, Final
Rule,'' 70 FR 28,606 (May 18, 2005) [also known as the Clean Air
Mercury Rule, or ``CAMR''], vacated on other grounds by New Jersey
v. EPA, 517 F.3d 574 (D.C. Cir. 2008), cert denied sub nom. Util.
Air Reg. Grp. v. New Jersey, 555 U.S. 1169 (2009); ``Standards of
Performance for New Stationary Sources and Emission Guidelines for
Existing Sources; Municipal Waste Combustors,'' 60 FR 65,387 (Dec.
19, 1995) (trading rules codified in 40 CFR 60.33b(d)(1)-(2)).
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G. Additional Factors That Can Help State Meet Their CO2
Emission Performance Goals
A resource available from the EPA for states pursuing market-based
approaches is the EPA's data and experience in support of state trading
programs and emissions data collection. For states needing technical
assistance with data or operation of market-based programs, existing
EPA data systems are a resource that have been used to collect
emissions data, track allowances and transfers, and determine
compliance for state programs. For example, New Hampshire was part of
the Ozone Transport Commission (OTC) trading program but was not
included in the NOx SIP Call. Because the state wanted its sources to
continue to participate in a state trading program, the EPA operated
the emissions trading program for New Hampshire sources, from
allocating allowances to compliance determination.
Additionally, as noted elsewhere in this preamble, more than 25
states have mandatory renewable portfolio standards, and other states
have voluntary renewable programs and goals. There is considerable
diversity among the states in the scope and coverage of these
standards, in particular in how renewable resources are defined. At the
federal level, the EPA has considered the greenhouse gas implications
related to biomass use at stationary sources through several actions,
including a call for information from stakeholders and the development
and review of the ``Accounting Framework for Biogenic CO2
Emissions from Stationary Sources,'' issued in September 2011. That
study was reviewed by the EPA's Science Advisory Board in 2011 and 2012
and the agency continues to assess the framework and consider the
latest scientific analyses and technical input received from
stakeholders. The EPA expects that the framework, when finalized, will
be a resource that could help inform states in the development of their
CAA section 111(d) plans.
H. Resources for States To Consider in Developing Their Plans
As part of the stakeholder outreach process, the EPA asked states
what the agency could do to facilitate state plan development and
implementation. Some states indicated that they wanted the EPA to
create resources to assist with state plan development, especially
resources related to accounting for end-use energy efficiency and
renewable energy (EE/RE) in state plans. They requested clear
methodologies for
[[Page 34928]]
measuring EE/RE policies and programs, so that these could be included
as part of their compliance strategies. Stakeholders said that these
tools and metrics should build upon the EPA's ``Roadmap for
Incorporating Energy Efficiency/Renewable Energy Policies and Programs
into State and Tribal Implementation Plans,''\313\ as well as the State
Energy Efficiency Action Network's ``Energy Efficiency Program Impact
Evaluation Guide.''\314\ The EPA also heard that states would like
examples of effective state policies and programs.
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\313\ http://epa.gov/airquality/eere/.
\314\ http://www1.eere.energy.gov/seeaction/index.html.
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As a result of this feedback, in consultation with U.S. Department
of Energy and other federal agencies, the EPA has developed a toolbox
of decision support resources and is making that available at a
dedicated Web site: http://www2.epa.gov/www2.epa.gov/cleanpowerplantoolbox. Current resources on the site focus on
approaches states and other entities have already taken that reduce
CO2 emissions from the electric utility sector.
For the final rulemaking, the EPA plans to organize resources on
the Web site around the following two categories: State plan guidance
and state plan decision support. The state plan guidance section will
serve as a central repository for the final emission guidelines,
regulatory impact analysis, technical support documents, and other
supporting materials. The state plan decision support section will
include information to help states evaluate different approaches and
measures they might consider as they initiate plan development. This
section will include, for example, a summary of existing state climate
and EE/RE policies and programs,\315\ National Action Plan for Energy
Efficiency (Action Plan),\316\ information on electric utility actions
that reduce CO2, and tools and information to assist with
translating energy savings into emission reductions.
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\315\ Appendix, State Plan Considerations TSD.
\316\ http://www.epa.gov/cleanenergy/energy-programs/suca/resources.html.
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We note that our inclusion of a measure in the toolbox does not
mean that a state plan must include that measure. In fact, inclusion of
measures provided at the Web site does not necessarily imply the
approvability of an approach or method for use in a state plan. States
will need to demonstrate that any measure included in a state plan
meets all relevant approvability criteria and adequately addresses
elements of the plan components discussed in Section VIII of this
preamble.
The EPA solicits comment on this approach and the information
currently included, and planned for inclusion, in the Decision Support
Toolbox.
IX. Implications for Other EPA Programs and Rules
A. Implications for New Source Review Program
The new source review (NSR) program is a preconstruction permitting
program that requires major stationary sources of air pollution to
obtain permits prior to beginning construction. The requirements of the
NSR program apply both to new construction and to modifications of
existing major sources. Generally, a source triggers these permitting
requirements as a result of a modification when it undertakes a
physical or operational change that results in a significant emission
increase and a net emissions increase. NSR regulations define what
constitutes a significant net emissions increase, and the concept is
pollutant-specific. For GHG emissions, the PSD applicability analysis
is described in the Prevention of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule (FR 75 31514, June 3, 2010). As a general
matter, a modifying major stationary source would trigger PSD
permitting requirements for GHGs if it emits GHGs in excess of 100,000
tons per year (tpy) of carbon dioxide equivalents (CO2e),
and it undergoes a change or change in the method of operation
(modification) resulting in an emissions increase of 75,000 tpy
CO2e as well as an increase on a mass basis. Once it has
been determined that a change triggers the requirements of the NSR
program, the source must obtain a permit prior to making the change.
The pollutant(s) at issue and the air quality designation of the area
where the facility is located or proposed to be built determine the
specific permitting requirements.
As part of its CAA section 111(d) plan, a state may impose
requirements that require an affected EGU to undertake a physical or
operational change to improve the unit's efficiency that results in an
increase in the unit's dispatch and an increase in the unit's annual
emissions. If the emissions increase associated with the unit's changes
exceeds the thresholds in the NSR regulations discussed above for one
or more regulated NSR pollutants, including the netting analysis, the
changes would trigger NSR.
While there may be instances in which an NSR permit would be
required, we expect those situations to be few. As previously discussed
in this preamble, states have considerable flexibility in selecting
varied measures as they develop their plans to meet the goals of the
emissions guidelines. One of these flexibilities is the ability of the
state to establish the standards of performance in their CAA section
111(d) plans in such a way so that their affected sources, in complying
with those standards, in fact would not have emissions increases that
trigger NSR. To achieve this, the state would need to conduct an
analysis consistent with the NSR regulatory requirements that supports
its determination that as long as affected sources comply with the
standards of performance in their CAA section 111(d) plan, the source's
emissions would not increase in a way that trigger NSR requirements.
For example, a state could decide to adjust its demand side
measures or increase reliance on renewable energy as a way of reducing
the future emissions of an affected source initially predicted (without
such alterations) to increase its emissions as a result of a CAA
section 111(d) plan requirement. In other words, a state plan's
incorporation of expanded use of cleaner generation or demand-side
measures could yield the result that units that would otherwise be
projected to trigger NSR through a physical change that might result in
increased dispatch would not, in fact, increase their emissions, due to
reduced demand for their operation. The state could also, as part of
its CAA section 111(d) plan, develop conditions for a source expected
to trigger NSR that would limit the unit's ability to move up in the
dispatch enough to result in a significant net emissions increase that
would trigger NSR (effectively establishing a synthetic minor limit).
\317\
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\317\ Certain stationary sources that emit or have the potential
to emit a pollutant at a level that is equal to or greater than
specified thresholds are subject to major source requirements. See,
e.g., CAA Sec. Sec. 165(a)(1), 169(1), 501(2), 502(a). A synthetic
minor limitation is a legally and practicably enforceable
restriction that has the effect of limiting emissions below the
relevant level and that a source voluntarily obtains to avoid major
stationary source requirements, such as the PSD or title V
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4),
70.2 (definition of ``potential to emit'').
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We request comment on whether, with adequate record support, the
state plan could include a provision, based on underlying analysis,
stating that an affected source that complies with its applicable
standard would be treated as not increasing its emissions, and if so,
whether such a provision would mean that, as a matter of law, the
source's actions to comply with its standard
[[Page 34929]]
would not subject the source to NSR. We also seek comment on the level
of analysis that would be required to support a state's determination
that sources will not trigger NSR when complying with the standards of
performance included in the state's CAA section 111(d) plan and the
type of plan requirements, if any, that would need to be included in
the state's plan.
As a result of such flexibility and anticipated state involvement,
we expect that a limited number of affected sources would trigger NSR
when states implement their plans.
B. Implications for Title V Program
The preamble to the re-proposed EGU NSPS (70 FR 1429-1519; January
8, 2014) explained that regulating GHGs for the first time under
section 111 of the CAA would make GHGs ``regulated air pollutants'' for
the first time under the operating permit regulations of 40 CFR parts
70 and 71. This would result in GHGs becoming ``fee pollutants'' in
certain state part 70 permit programs and in the EPA's part 71 permit
program, thus requiring the collection of fees for GHG emissions in
these programs. Where title V fees would be required for GHGs, they
would typically be charged at the same rate ($ per ton of pollutant) as
all other fee pollutants. This would likely result in excessive and
unnecessary fees being charged to subject sources. To avoid this
situation, we proposed to exempt GHGs from the fee rates in effect for
other fee pollutants, while proposing an alternative fee that would be
much lower than the fee charged to other fee pollutants, yet sufficient
to cover the costs of addressing GHGs in operating permits.
This title V fee issue is a one-time occurrence resulting from the
promulgation of the first CAA section 111 standard to regulate GHGs
(the EGU NSPS for new sources) and is not an issue for any other
subsequent CAA section 111 regulations, so there is no need to address
any title V fee issues in this proposal. Thus, we are not re-visiting
these title V fee issues in this proposal, and we are not proposing any
additional revisions to any title V regulations as part of this action.
The title V regulations require each permit to include emission
limitations and standards, including operational requirements and
limitations that assure compliance with all applicable requirements.
Requirements resulting from this rule that are imposed on affected EGUs
or any other potentially affected entities that have title V operating
permits are applicable requirements under the title V regulations and
would need to be incorporated into the source's title V permit in
accordance with the schedule established in the title V regulations.
For example, if the permit has a remaining life of three years or more,
a permit reopening to incorporate the newly applicable requirement
shall be completed no later than 18 months after promulgation of the
applicable requirement. If the permit has a remaining life of less than
three years, the newly applicable requirement must be incorporated at
permit renewal.
C. Interactions With Other EPA Rules
Existing fossil fuel-fired EGUs, such as those covered in this
proposal, are or will be potentially impacted by several other recently
finalized or proposed EPA rules.\318\ On February 16, 2012, the EPA
issued the mercury and air toxics standards (MATS) rule (77 FR 9304) to
reduce emissions of toxic air pollutants from new and existing coal-
and oil-fired EGUs. The MATS rule will reduce emissions of heavy
metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel
(Ni); and acid gases, including hydrochloric acid (HCl) and
hydrofluoric acid (HF). These toxic air pollutants, also known as
hazardous air pollutants or air toxics, are known or suspected of
causing damage to the nervous system, cancer, and other serious health
effects. The MATS rule will also reduce SO2 and fine
particle pollution, which will reduce particle concentrations in the
air and prevent thousands of premature deaths and tens of thousands of
heart attacks, bronchitis cases and asthma episodes.
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\318\ We discuss other rulemakings solely for background
purposes. The effort to coordinate rulemakings is not a defense to a
violation of the CAA. Sources cannot defer compliance with existing
requirements because of other upcoming regulations.
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The EPA is closely monitoring MATS compliance and finds that the
industry is making substantial progress. Plant owners are moving
proactively to install controls that will achieve the MATS performance
standards. Certain units, especially those that operate infrequently,
may be considered not worth investing in given today's electricity
market, and those are closing.
Existing sources subject to the MATS rule are given until April 16,
2015 to comply with the rule's requirements. The final MATS rule
provided a foundation on which states and other permitting authorities
could rely in granting an additional, fourth year for compliance
provided for by the CAA. States report that these fourth year
extensions are being granted. In addition, the EPA issued an
enforcement policy that provides a clear pathway for reliability-
critical units to receive an administrative order that includes a
compliance schedule of up to an additional year, if it is needed to
ensure electricity reliability.
On May 19, 2014, the EPA issued a final rule under section 316(b)
of the Clean Water Act (33 U.S.C. 1326(b)) (referred to hereinafter as
the 316(b) rule).\319\ This rule establishes new standards to reduce
injury and death of fish and other aquatic life caused by cooling water
intake structures at existing power plants and manufacturing
facilities.\320\ The 316(b) rule subjects existing power plants and
manufacturing facilities that withdraw in excess of 2 million gallons
per day (MGD) of cooling water, and use at least 25 percent of that
water for cooling purposes, to a national standard designed to reduce
the number of fish destroyed through impingement and a national
standard for establishing entrainment reduction requirements. All
facilities subject to the rule must submit information on their
operations for use by the permit authority in determining 316(b) permit
conditions. Certain plants that withdraw very large volumes of water
will also be required to conduct additional studies for use by the
permit authority in determining the site-specific entrainment reduction
measures for such facilities. The rule provides significant flexibility
for compliance with the impingement standards and, as a result, is not
projected to impose a substantial cost burden on affected facilities.
With respect to entrainment, the rule calls upon the permitting
authority to in establishing appropriate entrainment reduction
measures, taking into account, among other factors, compliance costs,
facility reliability and grid reliability. Existing sources subject to
the 316(b) rule are required to comply with the impingement
requirements as soon as practicable after the entrainment requirements
are determined. They must comply with applicable site-specific
entrainment reduction controls based on the schedule of requirements
established by the permitting authority.
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\319\ The pre-publication version of the final rule is available
at: http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/#final.
\320\ CWA section 316(b) provides that standards applicable to
point sources under sections 301 and 306 of the Act must require
that the location, design, construction and capacity of cooling
water intake structures reflect the best technology available for
minimizing adverse environmental impacts.
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The EPA is also reviewing public comments and working to finalize
two proposed rules which will also impact
[[Page 34930]]
existing fossil fuel-fired EGUs: The steam electric effluent limitation
guidelines (SE ELG) rule and the coal combustion residuals (CCR) rule.
These proposed rules are summarized below.
On June 7, 2013 (78 FR 34432), the EPA proposed the SE ELG rule to
strengthen the controls on discharges from certain steam electric power
plants by revising technology-based effluent limitations guidelines and
standards for the steam electric power generating point source
category. The current regulations, which were last updated in 1982, do
not adequately address the toxic pollutants discharged from the
electric power industry, nor have they kept pace with process changes
that have occurred over the last three decades. Existing steam electric
power plants currently contribute 50-60 percent of all toxic pollutants
discharged to surface waters by all industrial categories regulated in
the United States under the CWA. Furthermore, power plant discharges to
surface waters are expected to increase as pollutants are increasingly
captured by air pollution controls and transferred to wastewater
discharges. This proposed regulation, which includes new requirements
for both existing and new generating units, would reduce the amount of
toxic metals and other pollutants discharged to surface waters from
power plants.
On June 21, 2010 (75 FR 35128), the EPA proposed the CCR rule,
which co-proposed two approaches to regulating the disposal of coal
combustion residuals (CCRs) generated by electric utilities and
independent power producers. CCRs are residues from the combustion of
coal in steam electric power plants and include materials such as coal
ash (fly ash and bottom ash) and flue gas desulfurization (FGD) wastes.
Under one proposed approach, the EPA would list these residuals as
``special wastes,'' when destined for disposal in landfills or surface
impoundments, and would apply the existing regulatory requirements
established under Subtitle C of RCRA to such wastes. Under the second
proposed approach, the EPA would establish new regulations applicable
specifically to CCRs under subtitle D of RCRA, the section of the
statute applicable to solid (i.e., non-hazardous) wastes. Under both
approaches, CCRs that are beneficially used would remain exempt under
the Bevill exclusion.\321\ While the EPA still is evaluating all the
available information and comments, and while a final risk assessment
for the CCR rule has not yet been completed, reliance on data and
analyses discussed in the preamble to the recent SE ELG proposal might
have the potential to lower the CCR rule risk assessment results by as
much as an order of magnitude. If this proves to be the case, the EPA's
current thinking is that the revised risks, coupled with the ELG
requirements that the agency might promulgate, and the increased
federal oversight such requirements could achieve, could provide strong
support for a conclusion that regulation of CCR disposal under RCRA
Subtitle D would be adequate.\322\ The EPA is under a court-ordered
deadline to complete the CCR rulemaking by December 19, 2014.
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\321\ Beneficial use involves the reuse of CCRs in a product to
replace virgin raw materials that would otherwise be obtained
through extraction. The EPA encourages the beneficial use of CCRs in
an appropriate and protective manner, because this practice can
produce environmental, economic, and performance benefits. The
Agency recently evaluated the environmental impacts associated with
encapsulated beneficial uses of fly ash used as a direct substitute
for Portland cement in concrete, and FGD gypsum used as a
replacement for mined gypsum in wallboard. The EPA concluded that
the beneficial use of CCRs in concrete and wallboard is appropriate
because the environmental releases of constituents of potential
concern (COPC) during use by the consumer are comparable to or lower
than those from analogous non-CCR products, or are at or below
relevant regulatory and health-based benchmarks for human and
ecological receptors. See U.S. Environmental Protection Agency, Coal
Combustion Residual Beneficial Use Evaluation: Fly Ash Concrete and
FGD Gypsum Wallboard (2014).
\322\ U.S. EPA. September 2013. Regulatory Impact Analysis for
the Proposed Standards of Performance for Greenhouse Gas Emissions
for New Stationary Sources: Electric Utility Generating Units. EPA-
452/R-13-003. Available at http://www2.epa.gov/sites/production/files/2013-09/documents/20130920proposalria.pdf.
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The EPA recognizes the importance of assuring that each of the
rules described above can achieve its intended environmental objectives
in a commonsense, cost-effective manner, consistent with underlying
statutory requirements, and while assuring a reliable power system.
Executive Order (EO) 13563, ``Improving Regulation and Regulatory
Review,'' issued on January 18, 2011, states that ``[i]n developing
regulatory actions and identifying appropriate approaches, each agency
shall attempt to promote . . . coordination, simplification, and
harmonization. Each agency shall also seek to identify, as appropriate,
means to achieve regulatory goals that are designed to promote
innovation.'' Within the EPA, we are paying careful attention to the
interrelatedness and potential impacts on the industry, reliability and
cost that these various rulemakings can have.
As discussed in Sections VII and VIII of this preamble, the EPA is
proposing to give states broad flexibility in developing approvable
plans under CAA section 111(d), including the ability to adopt rate-
based or mass-based emission performance goals, and to rely on a wide
variety of CO2 emission reduction measures. The EPA is also
proposing to give states considerable flexibility with respect to the
timeframes for plan development and implementation, with up to two or
three years permitted for final plans to be submitted after the
proposed GHG emission guidelines are finalized, and up to fifteen years
for all emission reduction measures to be fully implemented. In light
of these flexibilities, we believe that states will have ample
opportunity, when developing and implementing their CAA section 111(d)
plans, to coordinate their response to this requirement with source and
state responses to any obligations that may be applicable to affected
EGUs as a result of the MATS, 316(b), SE ELG and CCR rules--all of
which are or will be final rules before this rulemaking is finalized--
and to do so in a manner that will help reduce cost and ensure
reliability, while also ensuring that all applicable environmental
requirements are met.\323\
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\323\ It should be noted that regulatory obligations imposed
upon states and sources operate independently under different
statutes and sections of statutes; the EPA expects that states and
sources will take advantage of available flexibilities as
appropriate, but will comply with all relevant legal requirements.
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The EPA is also endeavoring to enable EGUs to comply with
applicable obligations under other power sector rules as efficiently as
possible (e.g., by facilitating their ability to coordinate planning
and investment decisions with respect to those rules) and, where
possible, implement integrated compliance strategies. For example, in
the proposed SE ELG rule, the EPA describes its current thinking on how
it might effectively harmonize the potential requirements of that rule
with the requirements of the final CCR rule, to the extent that both
rules may regulate or affect the disposal of coal combustion wastes to
and from surface impoundments at power plants.\324\ The EPA's goal in
exploring how it might harmonize the SE ELG and CCR rules is to
minimize the overall complexity of the two regulatory structures and
avoid creating unnecessary burdens.\325\
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\324\ See: Federal Register Vol. 78, No. 110; June 7, 2013. Page
34441.
\325\ In considering how to coordinate the potential
requirements between the SE ELG and CCR rules, the EPA stated that
it is guided by the following policy considerations: First and
foremost, the EPA intends to ensure that its statutory
responsibilities to restore and maintain water quality under the CWA
and to protect human health and the environment under RCRA are
fulfilled. At the same time, the EPA would seek to minimize the
potential for overlapping requirements to avoid imposing any
unnecessary burdens on regulated entities and to facilitate
implementation and minimize the overall complexity of the regulatory
structure under which facilities must operate. Based on these
considerations, the EPA stated that it is exploring two primary
means of integrating the two rules: (1) Through coordinating the
design of any final substantive CCR regulatory requirements, and (2)
through coordination of the timing and implementation of final rule
requirements to provide facilities with a reasonable timeline for
implementation that allows for coordinated planning and protects
electricity reliability for consumers.
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[[Page 34931]]
In addition to the power sector rules discussed above, the
development of SIPs for criteria pollutants (PM2.5, ozone
and SO2) and regional haze may also have implications for
existing fossil-fired EGUs.
On June 6, 2013, the EPA proposed an implementation rule for the
2008 ozone National Ambient Air Quality Standards (NAAQS), to provide
rules and guidance to states on the development of approvable state
implementation plans (SIPs), including SIPs under CAA section 110
(infrastructure SIPs) and section 182 (ozone nonattainment SIPs). This
rule addresses the statutory requirements for areas that the EPA has
designated as nonattainment for the 2008 ozone standard. The agency is
currently working to finalize that rule. The EPA is also working on a
proposed transport rule that would identify the obligations of upwind
states that contribute to those downwind state ozone nonattainment
areas. This rule is scheduled for proposal in 2014 and to be finalized
by 2015.
The EPA is developing a proposed implementation rule to provide
guidance to states on the development of SIPs for the 2012
PM2.5 NAAQS.
The SO2 NAAQS was revised in June 2010 to protect public
health from the short-term effects of SO2 exposure. In July
2013, the EPA designated 29 areas in 16 states as nonattainment for the
SO2 NAAQS. The EPA based these nonattainment designations on
the most recent set of certified air quality monitoring data as well as
an assessment of nearby emission sources and weather patterns that
contribute to the monitored levels. The EPA intends to address the
designations for all other areas in separate actions in the future
\326\. The EPA has proposed the data requirements rule for the 1-hour
SO2 NAAQS to require states to characterize air quality more
extensively using ambient monitoring or air quality modeling
approaches.
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\326\ The EPA has developed a comprehensive implementation
strategy for these future actions that focuses resources on
identifying and addressing unhealthy levels of SO2 in
areas where people are most likely to be exposed to violations of
the standard. The strategy is available at: http://www.epa.gov/airquality/sulfurdioxide/implement.html.
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The EPA requires SIP updates every 10 years for regional haze, as
required by the EPA's Regional Haze Rule which was promulgated in 1999.
The next 10-year SIP revision for regional haze, covering the time
period through 2028, is due from each state by July 2018. Each SIP must
provide for reasonable progress towards visibility improvement in
protected scenic areas.
The development of these SIPs may, where applicable, have
significant implications for existing fossil fuel-fired EGUs, as well
as for the states that are responsible for developing them. The
timeframes for submittal of SIPs for the various programs and the
timeframes we are proposing for submittal of the CAA section 111(d)
state plans will allow considerable time for coordination by states in
the development of their respective plans. The EPA is willing to work
with states to assist them in coordinating their efforts across these
planning processes. The EPA believes that CAA section 111(d) efforts
and actions will tend to contribute to overall air quality improvements
and thus should be complementary to criteria pollutant and regional
haze SIP efforts.
In light of the broad flexibilities we are proposing in this
action, we believe that states will have ample opportunity to design
CAA section 111(d) plans that use innovative, cost-effective regulatory
strategies and that spark investment and innovation across a wide
variety of clean energy technologies. We also believe that the broad
flexibilities we are proposing in this action will enable states and
affected EGUs to build on their longstanding, successful records of
complying with multiple CAA, CWA, and other environmental requirements,
while assuring an adequate, affordable, and reliable supply of
electricity.
X. Impacts of the Proposed Action \327\
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\327\ The impacts presented in this section of the preamble
represent an illustrative implementation of the guidelines. As
states implement the proposed guidelines, they have sufficient
flexibility to adopt different state-level or regional approaches
that may yield different costs, benefits, and environmental impacts.
For example, states may use the flexibilities described in these
guidelines to find approaches that are more cost effective for their
particular state or choose approaches that shift the balance of co-
benefits and impacts to match broader state priorities.
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A. What are the air impacts?
The EPA anticipates significant emission reductions under the
proposed guidelines for the power sector. CO2 emissions are
projected to be reduced when compared to 2005 emissions, by 26 percent
to 27 percent in 2020 and about 30 percent in 2030 under Option 1.
Option 2 reflects reductions of about 23 percent in 2020 and 23 percent
to 24 percent in 2025 when compared to CO2 emissions in
2005. The guidelines are projected to result in substantial co-benefits
through reductions of SO2, PM2.5 and NOx that
will have direct public health benefits by lowering ambient levels of
these pollutants and ozone. Tables 10 and 11 show expected
CO2 and other air pollutant emission reductions in the base
case, with the proposed Option 1 for 2020, 2025, and 2030 and
regulatory alternative Option 2, for 2020 and 2025.
Table 10--Summary of CO2 and Other Air Pollutant Emission Reductions with Option 1
----------------------------------------------------------------------------------------------------------------
PM2.5
CO2 (million SO2 (thousands NOX (thousands (thousands of
metric tons) of tons) of tons) tons)
----------------------------------------------------------------------------------------------------------------
2020 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,161 1,476 1,559 212
Guidelines: 1,790 1,184 1,213 156
Emission Reductions......................... 371 292 345 56
----------------------------------------------------------------------------------------------------------------
2025 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,231 1,515 1,587 209
Guidelines: 1,730 1,120 1,166 150
[[Page 34932]]
Emission Reductions......................... 501 395 421 59
----------------------------------------------------------------------------------------------------------------
2030 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,256 1,530 1,537 198
Guidelines: 1,711 1,106 1,131 144
Emission Reductions......................... 545 424 407 54
----------------------------------------------------------------------------------------------------------------
2020 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,161 1,476 1,559 212
Guidelines: 1,777 1,140 1,191 154
Emission Reductions......................... 383 335 367 58
----------------------------------------------------------------------------------------------------------------
2025 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,231 1,515 1,587 209
Guidelines: 1,724 1,090 1,151 145
Emission Reductions......................... 506 425 436 63
----------------------------------------------------------------------------------------------------------------
2030 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case Proposed.......................... 2,256 1,530 1,537 198
Guidelines: 1,701 1,059 1,109 142
Emission Reductions......................... 555 471 428 56
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2014.
Table 11--Summary of CO2 and Air Pollutant Emission Reductions with Option 2
----------------------------------------------------------------------------------------------------------------
PM2.5
CO2 (million SO2 (thousands NOX (thousands (thousands of
metric tons) of tons) of tons) tons)
----------------------------------------------------------------------------------------------------------------
2020 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case................................... 2,161 1,476 1,559 212
Option 2.................................... 1,878 1,231 1,290 166
Emission Reductions......................... 283 244 268 46
----------------------------------------------------------------------------------------------------------------
2025 Regional Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case................................... 2,231 1,515 1,587 209
Option 2.................................... 1,862 1,218 1,279 165
Emission Reductions......................... 368 297 309 44
----------------------------------------------------------------------------------------------------------------
2020 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case................................... 2,161 1,476 1,559 212
Option 2.................................... 1,866 1,208 1,277 163
Emission Reductions......................... 295 267 281 49
----------------------------------------------------------------------------------------------------------------
2025 State Compliance Approach:
----------------------------------------------------------------------------------------------------------------
Base Case................................... 2,231 1,515 1,587 209
Option 2.................................... 1,855 1,188 1,271 161
Emission Reductions......................... 376 327 317 48
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2014.
The reductions in these tables do not account for reductions in
hazardous air pollutants (HAPs) that may occur as a result of this
rule. For instance, the fine particulate reductions presented above do
not reflect all of the reductions in many heavy metal particulates.
B. Comparison of Building Block Approaches
Though the EPA has determined that the 4-building block approach is
the BSER, we did analyze the impacts of both a combination of building
blocks 1 and 2 and the combination of all four building blocks. The
analysis indicates that the combined strategies of heat rate
improvements (building block 1) and re-dispatch (building block 2)
would result in overall CO2 emission reductions of
approximately 22 percent in 2020 (compared to 2005 emissions and
[[Page 34933]]
assuming state-level compliance). This compares to expected
CO2 emission reductions of approximately 27 percent for the
four-block BSER approach discussed below. The EPA analysis also
estimates 24-32 GW of additional coal-fired EGU retirements in 2020
(compared to 46-49 GW for the four-block approach) and an additional 3-
5 GW of oil/gas steam EGUs (compared to 16 GW for the four-block
approach). For both the two-block and the four-block approach, a
decrease in coal production and price is predicted in 2020. The
decrease in production is predicted at 20-23 percent for the two-block
approach, compared to a decrease of 25-27 percent for the four-block
approach. A 12 percent decrease in coal prices is predicted for the
two-block approach; while the four-block approach results in a 16 to 18
percent decrease. Under both approaches, the shifting in generation
from higher-emitting steam EGUs to lower-emitting NGCC units results in
an increase in natural gas production and price. The two-block approach
results in a production increase of 19-22 percent and a price increase
of 10-11 percent. The four-block approach results in a production
increase of 12-14 percent and a price increase of 9-12 percent. Both
the two-block and the four-block approaches result in construction of
additional NGCC capacity by 2020, with 11-18 GW of new NGCC for the
two-block approach and 20-22 GW of new NGCC capacity for the four-block
approach. However, while the two-block approach results in 5-17 GW of
new NGCC capacity in 2030, the four-block approach results in 32-35 GW
less NGCC capacity in 2030 relative to the base case (due to increased
use of renewable energy sources and decreased demand from
implementation of demand side energy efficiency measures). Also,
significantly, the two-block approach results in less than 500 MW of
new renewable energy capacity; while the four-block option results in
approximately 12 GW of new renewable generating capacity.
The EPA projects that the annual incremental compliance cost for
the building block 1 and 2 approach is estimated to be $3.2 to $4.4
billion in 2020 and $6.8 to $9.8 billion (2011$) in 2030, excluding the
costs associated with monitoring, reporting, and recordkeeping (MRR).
This compares to costs excluding MRR of $5.4 to $7.4 billion in 2020
and $7.3 to $8.8 billion in 2030 for the proposed Option 1 (2011$) as
discussed in Section X.E of this preamble.
The total combined climate benefits and health co-benefits for the
building block 1 and 2 approach are estimated to be $21 to $40 billion
in 2020 and $32 to $63 billion in 2030 (2011$ at a 3-percent discount
rate [model average]). The net benefits are estimated to be $18 to $36
billion in 2020 and $25 to $53 billion in 2030 (2011$ at a 3-percent
discount rate [model average]). For the purposes of this summary, we
list the climate benefits associated with the marginal value of the
model average at 3% discount rate, however we emphasize the importance
and value of considering the full range of SCC values. These building
block 1 and 2 benefit estimates compare to combined climate benefits
and health co-benefits of $33 to $57 billion in 2020 and $55 to $93
billion in 2030 (2011$ at a 3-percent discount rate [model average])
for the proposed Option 1. Net benefits are estimated to be $27 to $50
billion in 2020 and $48 to $84 billion in 2030 (2011$ at a 3-percent
discount rate [model average]) as discussed in Section X.G. and XI.A of
this preamble.\328\
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\328\ Note that the health co-benefits and net benefits for the
proposed Option 1 include PM co-benefits associated with directly
emitted PM2.5. In contrast, the building block 1 and 2
analysis does not include co-benefits related to directly emitted
PM2.5.
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C. Endangered Species Act
Consistent with the requirements of section 7(a)(2) of the
Endangered Species Act (ESA), the EPA has also considered the effects
of this proposed rule and has reviewed applicable ESA regulations, case
law, and guidance to determine what, if any, impact there may be to
listed endangered or threatened species or designated critical habitat.
Section 7(a)(2) of the ESA requires federal agencies, in consultation
with the U.S. Fish and Wildlife Service (FWS) and/or the National
Marine Fisheries Service, to ensure that actions they authorize, fund,
or carry out are not likely to jeopardize the continued existence of
federally listed endangered or threatened species or result in the
destruction or adverse modification of designated critical habitat of
such species. 16 U.S.C. 1536(a)(2). Under relevant implementing
regulations, section 7(a)(2) applies only to actions where there is
discretionary federal involvement or control. 50 CFR 402.03. Further,
under the regulations consultation is required only for actions that
``may affect'' listed species or designated critical habitat. 50 CFR
Sec. 402.14. Consultation is not required where the action has no
effect on such species or habitat. Under this standard, it is the
federal agency taking the action that evaluates the action and
determines whether consultation is required. See 51 FR 19926, 19949
(June 3, 1986). Effects of an action include both the direct and
indirect effects that will be added to the environmental baseline. 50
CFR 402.02. Indirect effects are those that are caused by the action,
later in time, and are reasonably certain to occur. Id. To trigger a
consultation requirement, there must thus be a causal connection
between the federal action, the effect in question, and the listed
species, and the effect must be reasonably certain to occur.
The EPA has considered the effects of this proposed rule and has
reviewed applicable ESA regulations, case law, and guidance to
determine what, if any, impact there may be to listed species or
designated critical habitat for purposes of section 7(a)(2)
consultation. The EPA notes that the projected environmental effects of
this proposal are positive: reductions in overall GHG emissions, and
reductions in PM and ozone-precursor emissions (SOX and
NOX). With respect to the projected GHG emission reductions,
the EPA does not believe that such reductions trigger ESA consultation
requirements under section 7(a)(2). In reaching this conclusion, the
EPA is mindful of significant legal and technical analysis undertaken
by FWS and the U.S. Department of the Interior in the context of
listing the polar bear as a threatened species under the ESA. In that
context, in 2008, FWS and DOI expressed the view that the best
scientific data available were insufficient to draw a causal connection
between GHG emissions and effects on the species in its habitat.\329\
The DOI Solicitor concluded that where the effect at issue is climate
change, proposed actions involving GHG emissions cannot pass the ``may
affect'' test of the section 7 regulations and thus are not subject to
ESA consultation. The EPA has also previously considered issues
relating to GHG emissions in connection with the requirements of ESA
section 7(a)(2). Although the GHG emission reductions projected for
this proposal are large (the highest estimate is reductions of 555 MMT
of CO2 in 2030--see Table 10 above), the EPA evaluated
larger reductions in assessing this same issue in the context of the
light duty vehicle GHG emission standards for model years 2012-2016 and
2017-2025. There the agency projected emission reductions roughly
double and four times those projected
[[Page 34934]]
here over the lifetimes of the model years in question \330\ and, based
on air quality modeling of potential environmental effects, concluded
that ``EPA knows of no modeling tool which can link these small, time-
attenuated changes in global metrics to particular effects on listed
species in particular areas. Extrapolating from global metric to local
effect with such small numbers, and accounting for further links in a
causative chain, remain beyond current modeling capabilities.'' EPA,
Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel
Economy Standards, Response to Comment Document for Joint Rulemaking at
4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion
after evaluating issues relating to potential improvements relevant to
both temperature and oceanographic pH outputs. The EPA's ultimate
finding was that ``any potential for a specific impact on listed
species in their habitats associated with these very small changes in
average global temperature and ocean pH is too remote to trigger the
threshold for ESA section 7 (a)(2).'' Id. The EPA believes that the
same conclusions apply to the present proposal, given that the
projected CO2 emission reductions are less than those
projected for either of the light duty vehicle rules. See, e.g., Ground
Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d
1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a
species from a federal action is extremely remote, ESA does not require
consultation).
---------------------------------------------------------------------------
\329\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum
from David Longly Bernhardt, Solicitor, U.S. Department of the
Interior re: ``Guidance on the Applicability of the Endangered
Species Act's Consultation Requirements to Proposed Actions
Involving the Emission of Greenhouse Gases'' (Oct. 3, 2008).
\330\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at
62894 Table III-68 (Oct. 15, 2012).
---------------------------------------------------------------------------
With regard to non-GHG air emissions, the EPA is also projecting
substantial reductions of SOX and NOX as a
collateral consequence of this proposal. However, CAA section 111(d)(1)
standards cannot directly control emissions of criteria pollutants.
Consequently, CAA section 111(d) provides no discretion to adjust the
standard based on potential impacts to endangered species of reduced
criteria pollutant emissions. Section 7(a)(2) consultation thus is not
required with respect to the projected reductions of criteria pollutant
emissions. See 50 CFR 402.03; see also, National Lime Ass'n v. EPA, 233
F. 3d 625, 638-39 (D.C. Cir. 2000) (although CAA section 112(b)(2)
prohibits the EPA from listing criteria pollutants as hazardous air
pollutants, the EPA may use PM as a surrogate for metal hazardous air
pollutants and reductions in PM do not constitute impermissible
regulation of a criteria pollutant).
Moreover, there are substantial questions as to whether any
potential for relevant effects results from any element of the proposed
rule or would result instead from the separate actions of States
establishing standards of performance for existing sources and
implementing and enforcing those standards. Cf. American Trucking
Assn's v. EPA, 175 F. 3d 1027, 1043-45 (D.C. Cir. 1999), rev'd on
different grounds sub nom., Whitman v. American Trucking Assn's, 531
U.S. 457 (2000) (National Ambient Air Quality Standards have no
economic impact, for purposes of Regulatory Flexibility Act, because
impacts result from the actions of States through their development,
implementation and enforcement of state implementation plans). Thus,
for example, although questions may exist whether actions such as
increased utilization of solar or wind power could have effects on
listed species, the EPA believes that such effects (if any) would
result from decisions and actions by states in developing, implementing
and enforcing their plans. The precise steps States choose to take in
that regard cannot be determined or ordered by this federal action, and
they are not sufficiently certain to be attributable to this proposed
rule for ESA purposes. Consequently, for this additional reason, the
EPA does not believe that this proposed rule (if enacted) would have
effects on listed species that would trigger the section 7 (a)(2)
consultation requirement.
D. What are the energy impacts?
The proposed guidelines have important energy market implications.
Under Option 1, average nationwide retail electricity prices are
projected to increase by roughly 6 to 7 percent in 2020 relative to the
base case, and by roughly 3 percent in 2030 (contiguous U.S.). Average
monthly electricity bills are anticipated to increase by roughly 3
percent in 2020, but decline by approximately 9 percent by 2030. This
is a result of the increasing penetration of demand-side programs that
more than offset increased prices to end users by their expected
savings from reduced electricity use.
The average delivered coal price to the power sector is projected
to decrease by 16 to 17 percent in 2020 and roughly 18 percent in 2030,
relative to the base case for Option 1. The EPA also projects that
electric power sector-delivered natural gas prices will increase by 9
to 12 percent in 2020, with negligible changes in 2030. Natural gas use
for electricity generation will increase by as much as 1.2 trillion
cubic feet (TCF) in 2020 relative to the base case, and then begin to
decline over time.
These figures reflect the EPA's illustrative modeling that presumes
policies that lead to dispatch changes in 2020 and growing use of
energy efficiency and renewable electricity generation out to 2029. If
states make different policy choices, impacts could be different. For
instance, if states implement renewable and/or energy efficiency
policies on a more aggressive time-frame, impacts on natural gas and
electricity prices would likely be less. Implementation of other
measures not included in the EPA's BSER calculation or compliance
modeling, such as nuclear uprates, transmission system improvements,
use of energy storage technologies or retrofit CCS, could also mitigate
gas price and/or electricity price impacts.
The EPA projects coal production for use by the power sector, a
large component of total coal production, will decline by roughly 25 to
27 percent in 2020 from base case levels. The use of coal by the power
sector will decrease roughly 30 to 32 percent in 2030. Renewable energy
capacity is anticipated to increase by roughly 12 GW in 2020 and by 9
GW in 2030 under Option 1. Energy market impacts from the guidelines
are discussed more extensively in the RIA found in the docket for this
rulemaking.
E. What are the compliance costs?
The compliance costs of this proposed action are represented in
this analysis as the change in electric power generation costs between
the base case and the proposed rule in which states pursue a distinct
set of strategies beyond the strategies taken in the base case to meet
the terms of the EGU GHG emission guidelines, and include cost
estimates for demand-side energy efficiency. The compliance
assumptions--and, therefore, the projected compliance costs--set forth
in this analysis are illustrative in nature and do not represent the
full suite of compliance flexibilities states may ultimately pursue.
These illustrative compliance scenarios are designed to reflect, to the
extent possible, the scope and the nature of the proposed guidelines.
However, there is considerable uncertainty with regards to the precise
measures that states will adopt to meet the proposed requirements,
because there are considerable flexibilities afforded to the states in
developing their state plans.
The EPA projects that the annual incremental compliance cost of
Option 1 is estimated to be between $5.5 and $7.5 billion in 2020 and
between $7.3
[[Page 34935]]
and $8.8 billion (2011$) in 2030, including the costs associated with
monitoring, reporting, and recordkeeping (MRR). The incremental
compliance cost of Option 2 is estimated to be between $4.3 and $5.5
billion in 2020, including MRR costs. In 2025, the estimated compliance
cost of Option 2 is estimated to be between $4.5 and $5.5 billion (with
the assumed levels of end-use energy efficiency). These important
dynamics are discussed in more detail in the RIA in the rulemaking
docket. The annualized incremental cost is the projected additional
cost of complying with the guidelines in the year analyzed, and
includes the amortized cost of capital investment, needed new capacity,
shifts between or amongst various fuels, deployment of energy
efficiency programs, and other actions associated with compliance. MRR
costs are estimated to be $68.3 million (2011$) in 2020 and $8.9
million in 2025 and 2030 for Option 1 and $68.3 million in 2020 and
$8.9 million in 2025 for Option 2. More detailed cost estimates are
available in the RIA included in the rulemaking docket.
F. What are the economic and employment impacts?
The proposed standards are projected to result in certain changes
to power system operation as a result of the application of state
emission rate goals. Overall, we project dispatch changes, changes to
fossil fuel and retail electricity prices, and some additional coal
retirements. Average electric power sector-delivered natural gas prices
are projected to increase by roughly 9 to 12 percent in 2020 in Option
1, with negligible changes by 2030. Under Option 2, electric power
sector natural gas prices are projected to increase by roughly 8
percent in 2020, on an average nationwide basis, and increase by 1
percent or less in 2025. The average delivered coal price to the power
sector is projected to decrease by 16 to 17 percent in 2020 under
Option 1, and decrease by roughly 14 percent under Option 2, on a
nationwide average basis. Retail electricity prices are projected to
increase 6 to 7 percent under Option 1 and increase by roughly 4
percent under Option 2, both in 2020 and on an average basis across the
contiguous U.S. By 2030 under Option 1, electricity prices are
projected to increase by about 3 percent. Under Option 1, the EPA
projects 46 to 50 GW of additional coal-fired generation may be
uneconomic to maintain and may be removed from operation by 2030. The
EPA projects that under Option 2, 30 to 33 GW of additional coal-fired
generation may be uneconomic to maintain and may be removed from
operation by 2025.
It is important to note that the EPA's modeling does not
necessarily account for all of the factors that may influence business
decisions regarding future coal fired capacity. By 2025, the average
age of the coal-fired fleet will be 49 years old and twenty percent of
the fleet will be more than 60 years old. Many power companies already
factor a carbon price into their long term capacity planning that would
further influence business decisions to replace these aging assets with
modern, and significantly cleaner generation.
The compliance modeling done to support the proposal assumes that
overall electric demand will decrease significantly, as states ramp up
programs that result in lower overall demand. End-use energy efficiency
levels increase such that they achieve about an 11 percent reduction on
overall electricity demand levels in 2030 for Option 1, and a reduction
in overall electricity demand of approximately 6 percent reduction in
2025 for Option 2. In response, there are anticipated to be notable
changes to costs, prices, and electricity generation in the power
sector as more end-use efficiency is realized.
Changes in price or demand for electricity, natural gas, coal, can
impact markets for goods and services produced by sectors that use
these energy inputs in the production process or supply those sectors.
Changes in cost of production may result in changes in price, changes
in quantity produced, and changes in profitability of firms affected.
The EPA recognizes that these guidelines provide significant
flexibilities and states implementing the guidelines may choose to
mitigate impacts to some markets outside the EGU sector. Similarly,
demand for new generation or energy efficiency can result in shifts in
production and profitability for firms that supply those goods and
services, and the guidelines provide flexibility for states that may
want to enhance demand for goods and services from those sectors.
Executive Order 13563 directs federal agencies to consider the
effect of regulations on job creation and employment. According to the
Executive Order, ``our regulatory system must protect public health,
welfare, safety, and our environment while promoting economic growth,
innovation, competitiveness, and job creation. It must be based on the
best available science.'' (Executive Order 13563, 2011) Although
standard benefit-cost analyses have not typically included a separate
analysis of regulation-induced employment impacts, we typically conduct
employment analyses. During periods of sustained high unemployment,
employment impacts are of particular concern and questions may arise
about their existence and magnitude.
States have the responsibility and flexibility to implement
policies and practices for compliance with Proposed Electric Generating
Unit Greenhouse Gas Existing Source Guidelines. Quantifying the
associated employment impacts is complicated by the wide range of
approaches that States may use. As such, the EPA's employment analysis
includes projected employment impacts associated with illustrative
compliance scenarios for these guidelines for the electric power
industry, coal and natural gas production, and demand-side energy
efficiency activities. These projections are derived, in part, from a
detailed model of the electricity production sector used for this
regulatory analysis, and U.S government data on employment and labor
productivity. In the electricity, coal, and natural gas sectors, the
EPA estimates that these guidelines could have an employment impact of
roughly 25,900 to 28,000 job-years increase in 2020 for Option 1, state
to regional compliance approach, respectively. For Option 2, the state
and regional compliance approach estimates are 26,700 to 29,800 job-
years increase in 2020. Demand-side energy efficiency employment
impacts are approximately an increase of 78,800 jobs in 2020 for Option
1 and of 57,000 jobs for Option 2. By its nature, energy efficiency
reduces overall demand for electric power. The EPA recognizes as more
efficiency is built into the U.S. power system over time, lower fuel
requirements may lead to fewer jobs in the coal and natural gas
extraction sectors, as well as in EGU construction and operation than
would otherwise have been expected. The EPA also recognizes the fact
that, in many cases, employment gains and losses that might be
attributable to this rule would be expected to affect different sets of
people. Moreover, workers who lose jobs in these sectors may find
employment elsewhere just as workers employed in new jobs in these
sectors may have been previously employed elsewhere. Therefore, the
employment estimates reported in these sectors may include workers
previously employed elsewhere. This analysis also does not capture
potential economy-wide impacts due to changes in prices (of fuel,
electricity, labor, etc.). For these reasons, the numbers reported here
[[Page 34936]]
should not be interpreted as a net national employment impact.
G. What are the benefits of the proposed goals?
Implementing the proposed standards will generate benefits by
reducing emissions of CO2 as well as criteria pollutants and
their precursors, including SO2, NOX and directly
emitted particles. SO2 and NOX are precursors to
PM2.5 (particles smaller than 2.5 microns), and
NOX is a precursor to ozone. The estimated benefits
associated with these emission reductions are beyond those achieved by
previous EPA rulemakings including the Mercury and Air Toxics Standards
rule. The health and welfare benefits from reducing air pollution are
considered co-benefits for these standards. For this rulemaking, we
were only able to quantify the climate benefits from reduced emissions
of CO2 and the health co-benefits associated with reduced
exposure to PM2.5 and ozone. In summary, we estimate the
total combined climate benefits and health co-benefits for Option 1 to
be $33 billion to $54 billion in 2020 and $55 billion to $89 billion in
2030 assuming a regional compliance approach (2011 dollars at a 3-
percent discount rate [model average]). If states comply using a state-
specific compliance approach, these climate and health co-benefits
estimates are estimated to be $35 to $57 billion in 2020 and $57 to $93
billion in 2030 (2011 dollars at a 3-percent discount rate [model
average]). We also estimate the total combined climate benefits and
health co-benefits for Option 2 to be $26 billion to $44 billion in
2020 and $36 billion to $59 billion in 2025 (regional compliance
approach, 2011 dollars at a 3-percent discount rate [model average]).
Assuming a state compliance approach, the total combined climate
benefits and health co-benefits for Option 2 are estimated to be $27
billion to $45 billion in 2020 and $36 billion to $60 billion in 2025
(2011 dollars at a 3-percent discount rate [model average]). A summary
of the emission reductions and monetized benefits estimated for this
rule at all discount rates and additional analysis years is provided in
Tables 12 through 17 of this preamble.
Table 12--Summary of the Monetized Global Climate Benefits for the Proposed Option 1
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
Monetized climate benefits
-----------------------------------
2020 Discount rate (statistic) Regional
compliance State compliance
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)... ................................... 371 383
5 percent (average SCC)............ $4.7 $4.9
3 percent (average SCC)............ $17 $18
2.5 percent (average SCC).......... $25 $26
3 percent (95th percentile SCC).... $51 $52
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)... ................................... 501 506
5 percent (average SCC)............ $7.5 $7.6
3 percent (average SCC)............ $25 $25
2.5 percent (average SCC).......... $37 $37
3 percent (95th percentile SCC).... $76 $77
----------------------------------------------------------------------------------------------------------------
2030
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)... ................................... 545 555
5 percent (average SCC)............ $9.3 $9.5
3 percent (average SCC)............ $30 $31
2.5 percent (average SCC).......... $44 $44
3 percent (95th percentile SCC).... $92 $94
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global social
cost of carbon (SCC) estimates for the analysis years (2020, 2025, and 2030) and are rounded to two
significant figures.
Table 13--Summary of the Monetized Global Climate Benefits for the Option 2
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
Monetized climate benefits
-----------------------------------
2020 Discount rate (statistic) Regional State
compliance compliance
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)... ................................... 283 295
5 percent (average SCC)............ $3.6 $3.8
3 percent (average SCC)............ $13 $14
2.5 percent (average SCC).......... $19 $20
3 percent (95th percentile SCC).... $39 $40
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million metric tons)... ................................... 368 376
5 percent (average SCC)............ $5.5 $5.6
3 percent (average SCC)............ $18 $19
[[Page 34937]]
2.5 percent (average SCC).......... $27 $28
3 percent (95th percentile SCC).... $56 $57
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global SCC
estimates for the analysis years (2020, 2025, and 2030) and are rounded to two significant figures.
Table 14--Summary of the Monetized Health Co-Benefits for the Proposed Standards Option 1 Regional Compliance
Approach in the U.S.
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
National
emission Monetized health Monetized health
Pollutant reductions co- benefits (3 co- benefits (7
(thousands of percent percent
short tons) discount) discount)
----------------------------------------------------------------------------------------------------------------
Option 1 Regional Compliance Approach 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2................................................... 292 $12 to $26 $11 to $24
Directly emitted PM2.5 (Elemental Carbon and Organic 6 $0.75 to $1.7 $0.67 to $1.5
Carbon)..............................................
Directly emitted PM2.5 (crustal)...................... 44 $0.77 to $1.7 $0.69 to $1.6
NOX................................................... 345 $2.2 to $5.0 $2.0 to $4.5
Ozone precursor: \c\ ................ ................ ................
NOX (ozone season only)............................... 146 $0.63 to $2.7 $0.63 to $2.7
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits.......................................... $16 to $37 $15 to $34
Total Monetized Health Co-benefits combined with Monetized Climate Benefits $33 to $54 $32 to $51
\d\........................................................................
----------------------------------------------------------------------------------------------------------------
Option 1 Regional Compliance Approach 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\ ................ ................ ................
SO2................................................... 395 $17 to $38 $15 to $35
Directly emitted PM2.5 (Elemental Carbon and Organic 6 $0.85 to $1.9 $0.76 to $1.7
Carbon)..............................................
Directly emitted PM2.5 (crustal)...................... 46 $0.78 to $1.8 $0.70 to $1.6
NOX................................................... 421 $3.0 to $6.8 $2.7 to $6.1
Ozone precursor: \c\ ................ ................ ................
NOX (ozone season only)................................... 180 $1.0 to $4.3 $1.0 to $4.3
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits.......................................... $23 to $53 $21 to $48
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits combined with Monetized Climate Benefits $48 to $78 $46 to $74
\d\........................................................................
----------------------------------------------------------------------------------------------------------------
Option 1 Regional Compliance Approach 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2................................................... 424 $20 to $44 $18 to $40
Directly emitted PM2.5 (Elemental Carbon and Organic 5 $0.84 to $1.9 $0.76 to $1.7
Carbon)..............................................
Directly emitted PM2.5 (crustal)...................... 42 $0.77 to $1.7 $0.70 to $1.6
NOX................................................... 407 $3.0 to $6.7 $2.7 to $6.1
Ozone precursor: \c\
NOX(ozone season only).................................... 176 $1.1 to $4.5 $1.1 to $4.5
----------------------------------------------------------------------------------------------------------------
Total Monetized Health Co-benefits...................................... $25 to $59 $23 to $54
Total Monetized Health Co-benefits combined with Monetized Climate $55 to $89 $53 to $84
Benefits \d\...........................................................
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so
estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
as a range reflecting the use of two concentration-response functions, with the lower end of the range based
on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
These models assume that all fine particles, regardless of their chemical composition, are equally potent in
causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
over time. For the purposes of this table, we show the benefits associated with the model average at 3%
discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
provide combined climate and health estimates based on additional discount rates in the RIA.
[[Page 34938]]
Table 15--Summary of the Monetized Health Co-Benefits in the U.S. for the Proposed Guidelines Option 1 State
Compliance Approach
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
National
emission Monetized health co- Monetized health co-
Pollutant reductions benefits (3 percent benefits (7 percent
(thousands of discount) discount)
short tons)
----------------------------------------------------------------------------------------------------------------
Option 1 State Compliance Approach in 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \ b\
SO2..................................... 335 $13 to $29................ $11 to $26
Directly emitted PM2.5 (Elemental Carbon 6 $0.76 to $1.7............. $0.69 to $1.6
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 45 $0.79 to $1.8............. $0.71 to $1.6
NOX..................................... 367 $2.2 to $4.9.............. $2.0 to $4.4
Ozone precursor: \c\
NOX (ozone season only)................. 157 $0.64 to $2.7............. $0.64 to $2.7
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $17 to $40................ $15 to $36
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $35 to $57................ $33 to $54
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
Option 1 State Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2..................................... 425 $18 to $40................ $16 to $36
Directly emitted PM2.5 (Elemental Carbon 6 $0.90 to $2.0............. $0.81 to $1.8
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 49 $0.83 to $1.9............. $0.75 to $1.7
NOX..................................... 436 $2.9 to $6.5.............. $2.6 to $5.8
Ozone precursor: \c\
NOX (ozone season only)................. 190 $1.0 to $4.4.............. $1.0 to $4.4
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $23 to $54................ $21 to $49
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $49 to $80................ $46 to $75
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
Option 1 State Compliance Approach in 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2..................................... 471 $21 to $47................ $19 to $43
Directly emitted PM2.5 (Elemental Carbon 6 $0.87 to $2.0............. $0.78 to $1.8
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 44 $0.80 to $1.8............. $0.72 to $1.6
NOX..................................... 428 $2.9 to $6.6.............. $2.6 to $6.0
Ozone precursor: \c\
NOX (ozone season only)................. 187 $1.1 to $4.6.............. $1.1 to $4.6
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $27 to $62................ $24 to $57
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $57 to $93................ $55 to $87
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025, 2030) and are rounded to two significant figures, so
estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
as a range reflecting the use of two concentration-response functions, with the lower end of the range based
on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
These models assume that all fine particles, regardless of their chemical composition, are equally potent in
causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
over time. For the purposes of this table, we show the benefits associated with the model average at 3%
discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
provide combined climate and health estimates based on additional discount rates in the RIA.
Table 16--Summary of the Monetized Health Co-Benefits in the U.S. for the Option 2 Regional Compliance Approach
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
National
emission Monetized health co- Monetized health co-
Pollutant reductions benefits (3 percent benefits (7 percent
(thousands of discount) discount)
short tons)
----------------------------------------------------------------------------------------------------------------
Option 2 Regional Compliance Approach 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2..................................... 244 $9.8 to $22............... $8.9 to $20
Directly emitted PM2.5 (Elemental Carbon 5 $0.61 to $1.4............. $0.55 to $1.2
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 36 $0.63 to $1.4............. $0.57 to $1.3
NOX..................................... 268 $1.7 to $3.9.............. $1.6 to $3.5
Ozone precursor: \c\
[[Page 34939]]
NOX (ozone season only)................. 111 $0.47 to $2.0............. $0.47 to $2.0
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $13 to $31................ $12 to $28
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $26 to $44................ $25 to $41
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
Option 2 Regional Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
SO2..................................... 297 $13 to $29................ $12 to $26
Directly emitted PM2.5 (Elemental Carbon 4 $0.64 to $1.4............. $0.58 to $1.3
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 34 $0.59 to $1.3............. $0.53 to $1.2
NOX..................................... 309 $2.2 to $5.0.............. $2.0 to $4.5
Ozone precursor: \c\
NOX (ozone season only)................. 129 $0.73 to $3.1............. $0.73 to $3.1
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $17 to $40................ $16 to $36
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $36 to $59................ $34 to $55
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so
estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
as a range reflecting the use of two concentration-response functions, with the lower end of the range based
on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
These models assume that all fine particles, regardless of their chemical composition, are equally potent in
causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
over time. For the purposes of this table, we show the benefits associated with the model average at 3%
discount rate, however we emphasize the importance and value of considering the full range of SCC values. We
provide combined climate and health estimates based on additional discount rates in the RIA.
Table 17--Summary of the Monetized Health Co-Benefits in the U.S. for Option 2 State Compliance Approach
[Billions of 2011 dollars] \a\
----------------------------------------------------------------------------------------------------------------
National
emission Monetized health co- Monetized health co-
Pollutant reductions benefits (3 percent benefits (7 percent
(thousands of discount) discount)
short tons)
----------------------------------------------------------------------------------------------------------------
Option 2 State Compliance Approach in 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors:\b\
SO2..................................... 267 $10 to $23................ $9.1 to $21
Directly emitted PM2.5 (Elemental Carbon 5 $0.64 to $1.5............. $0.58 to $1.3
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 38 $0.66 to $1.5............. $0.60 to $1.4
NOX..................................... 281 $1.7 to $3.8.............. $1.5 to $3.4
Ozone precursor:\c\
NOX (ozone season only)................. 119 $0.48 to $2.1............. $0.48 to $2.1
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $14 to $32................ $12 to $29
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $27 to $45................ $26 to $42
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
Option 2 State Compliance Approach in 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors:\ b\
SO2..................................... 327 $14 to $30................ $12 to $27
Directly emitted PM2.5 (Elemental Carbon 5 $0.69 to $1.6............. $0.63 to $1.4
and Organic Carbon).
Directly emitted PM2.5 (crustal)........ 38 $0.64 to $1.4............. $0.58 to $1.3
NOX..................................... 317 $2.1 to $4.7.............. $1.9 to $4.2
Ozone precursor:\c\
[[Page 34940]]
NOX (ozone season only)................. 136 $0.72 to $3.1............. $0.72 to $3.1
-----------------------------------------------------------------------
Total Monetized Health Co-benefits.................. $18 to $41................ $16 to $16
-----------------------------------------------------------------------
Total Monetized Health Co-benefits combined with $36 to $60................ $35 to $56
Monetized Climate Benefits \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the analysis years (2020, 2025) and are rounded to two significant figures, so
estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health
effects from direct exposure to SO2, direct exposure to NO2, ecosystem effects or visibility impairment. Air
pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2, NOX and directly emitted PM2.5. PM co-benefits are shown
as a range reflecting the use of two concentration-response functions, with the lower end of the range based
on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012).
These models assume that all fine particles, regardless of their chemical composition, are equally potent in
causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of
effect estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), which each increase
over time. For the purposes of this table, we show the benefits associated with the model average at 3%
discount rate; however, we emphasize the importance and value of considering the full range of SCC values. We
provide combined climate and health estimates based on additional discount rates in the RIA.
The EPA has used the social cost of carbon (SCC) estimates
presented in the 2013 Technical Support Document: Technical Update of
the Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866 (2013 SCC TSD) to analyze CO2 climate
impacts of this rulemaking.\331\ We refer to these estimates, which
were developed by the U.S. government, as ``SCC estimates.'' The U.S.
government first published the SCC estimates in 2010 following an
interagency process that included the EPA and other executive branch
entities; the process used three integrated assessment models (IAM) to
develop SCC estimates and selected four global values for use in
regulatory analyses. The U.S. government recently updated these
estimates using new versions of each integrated assessment model and
published them in 2013. The 2013 update did not revisit the 2010
modeling decisions (e.g., with regard to the discount rate, reference
case socioeconomic and emission scenarios or equilibrium climate
sensitivity). Rather, improvements in the way damages are modeled are
confined to those that have been incorporated into the latest versions
of the models by the developers themselves and published in the peer-
reviewed literature. The 2010 SCC Technical Support Document (2010 SCC
TSD) provides a complete discussion of the methods used to develop
these estimates and the 2013 SCC TSD presents and discusses the updated
estimates.\332\
---------------------------------------------------------------------------
\331\ Docket ID EPA-HQ-OAR-2013-0495, Technical Support
Document: Technical Update of the Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866, Interagency
Working Group on Social Cost of Carbon, with participation by
Council of Economic Advisers, Council on Environmental Quality,
Department of Agriculture, Department of Commerce, Department of
Energy, Department of Transportation, Environmental Protection
Agency, National Economic Council, Office of Energy and Climate
Change, Office of Management and Budget, Office of Science and
Technology Policy, and Department of Treasury (May 2013, Revised
November 2013). Available at: http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-cost-of-carbon-for-regulator-impact-analysis.pdf.
\332\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866, Interagency Working Group on Social Cost of
Carbon, with participation by the Council of Economic Advisers,
Council on Environmental Quality, Department of Agriculture,
Department of Commerce, Department of Energy, Department of
Transportation, Environmental Protection Agency, National Economic
Council, Office of Energy and Climate Change, Office of Management
and Budget, Office of Science and Technology Policy, and Department
of Treasury (February 2010). Also available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf>.
---------------------------------------------------------------------------
The EPA and other agencies have sought public comment on the SCC
estimates as part of various rulemakings. In addition, OMB's Office of
Information and Regulatory Affairs recently sought public comment on
the approach used to develop the estimates. The comment period ended on
February 26, 2014, and OMB is reviewing the comments received.
The four SCC estimates, updated in 2013, are as follows: $13, $46,
$68, and $137 per metric ton of CO2 emissions in the year
2020 (2011 dollars).\333\ The first three values are based on the
average SCC from the three IAMs, at discount rates of 5, 3, and 2.5
percent, respectively. SCCs at several discount rates are included
because the literature shows that the SCC is quite sensitive to
assumptions about the discount rate, and because no consensus exists on
the appropriate rate to use in an intergenerational context (where
costs and benefits are incurred by different generations). The fourth
value is the 95th percentile of the SCC from all three models at a 3
percent discount rate. It is included to represent higher-than-expected
impacts from temperature change further out in the tails of the SCC
distribution (representing less likely, but potentially catastrophic,
outcomes).
---------------------------------------------------------------------------
\333\ The 2010 and 2013 TSDs present SCC in $2007. The estimates
were adjusted to 2011$ using the GDP Implicit Price Deflator. Also
available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
---------------------------------------------------------------------------
The 2010 SCC TSD noted a number of limitations to the SCC analysis,
including the incomplete way in which the integrated assessment models
capture catastrophic and non-catastrophic impacts, their incomplete
treatment of adaptation and
[[Page 34941]]
technological change, uncertainty in the extrapolation of damages to
high temperatures, and assumptions regarding risk aversion. Current
integrated assessment models do not assign value to all of the
important physical, ecological, and economic impacts of climate change
recognized in the climate change literature for various reasons,
including the inherent difficulties in valuing non-market impacts and
the fact that the science incorporated into these models understandably
lags behind the most recent research. Nonetheless, these estimates and
the discussion of their limitations represent the best available
information about the social benefits of CO2 emission
reductions to inform the benefit-cost analysis. Model developers
continually update the models to incorporate recent research. The new
versions of the models used to estimate the values presented in this
rulemaking offer some improvements in these areas identified above,
although further work is warranted. Accordingly, the EPA and other
parties continue to conduct research on modeling and valuation of
climate impacts with the goal of improving these estimates. Additional
details are provided in the SCC TSDs.
The health co-benefits estimates represent the total monetized
human health benefits for populations exposed to reduced
PM2.5 and ozone resulting from emission reductions under
illustrative compliance options for the proposed standards. Unlike the
global SCC estimates, the air pollution health co-benefits are
estimated for the contiguous U.S. only. We used a ``benefit-per-ton''
approach to estimate the benefits of this rulemaking. To create the
PM2.5 benefit-per-ton estimates, this approach uses a model
to convert emissions of PM2.5 precursors into changes in
ambient PM2.5 levels and another model to estimate the
changes in human health effects associated with that change in air
quality, which are then divided by the emissions in specific sectors.
We derived national average benefit-per-ton estimates for the EGU
sector using the approach published in Fann et al. (2012),\334\ and
updated those estimates to reflect the studies and population data in
the 2012 PM NAAQS RIA. We further separated the national estimates into
regional estimates to provide greater spatial resolution.\335\ In
addition, we generated regional benefit-per-ton estimates for changes
in ozone exposure. The ozone estimates used the ozone information from
the sector modeling for the EGU sector described in Fann et al. (2012)
and the health impact assumptions used in the Ozone NAAQS
RIAs.336 337 To calculate the co-benefits for the proposed
standards, we multiplied the regional benefit-per-ton estimates for the
EGU sector by the corresponding emission reductions.\338\ All benefit-
per-ton estimates reflect the geographic distribution of the modeled
emissions, which may not exactly match the emission reductions in this
rulemaking, and thus they may not reflect the local variability in
population density, meteorology, exposure, baseline health incidence
rates, or other local factors for any specific location. More
information regarding the derivation of the benefit-per-ton estimates
is available in the RIA.
---------------------------------------------------------------------------
\334\ Fann, N., K.R. Baker and C.M. Fulcher. 2012.
``Characterizing the PM2.5-related health benefits of
emission reductions for 17 industrial, area and mobile emission
sectors across the U.S.'' Environment International 49 41-151.
\335\ U.S. Environmental Protection Agency (U.S. EPA). 2012.
Regulatory Impact Analysis for the Final Revisions to the National
Ambient Air Quality Standards for Particulate Matter. Research
Triangle Park, NC: Office of Air Quality Planning and Standards,
Health and Environmental Impacts Division. (EPA document number EPA-
452/R-12-003, December). Available at: <http://www.epa.gov/pm/2012/finalria.pdf>.
\336\ U.S. Environmental Protection Agency (U.S. EPA). 2008b.
Final Ozone NAAQS Regulatory Impact Analysis. Research Triangle
Park, NC: Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division, Air Benefit and Cost Group Research.
(EPA document number EPA-452/R-08-003, March). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>.
\337\ U.S. Environmental Protection Agency (U.S. EPA). 2010.
Section 3: Re-analysis of the Benefits of Attaining Alternative
Ozone Standards to Incorporate Current Methods. Available at <http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-5.09.pdf>.
\338\ U.S. Environmental Protection Agency. 2013. Technical
support document: Estimating the benefit per ton of reducing PM2.5
precursors from 17 sectors. Research Triangle Park, NC: Office of
Air and Radiation, Office of Air Quality Planning and Standards,
January. Available at: <http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf>.
---------------------------------------------------------------------------
These models assume that all fine particles, regardless of their
chemical composition, are equally potent in causing premature mortality
because the scientific evidence is not yet sufficient to allow
differentiation of effect estimates by particle type. Even though we
assume that all fine particles have equivalent health effects, the
benefit-per-ton estimates vary between precursors depending on the
location and magnitude of their impact on PM2.5 levels,
which drive population exposure.
It is important to note that the magnitude of the PM2.5
and ozone co-benefits is largely driven by the concentration response
functions for premature mortality and the value of a statistical life
used to value reductions in premature mortality. For PM2.5,
we cite two key empirical studies, one based on the American Cancer
Society cohort study \339\ and the extended Six Cities cohort
study.\340\ We present the PM2.5 co-benefits results as a
range based on the concentration-response functions from these two
epidemiology studies, but this range does not capture the full range of
uncertainty inherent in the co-benefits estimates. In the RIA for this
rule, which is available in the docket, we also include
PM2.5 co-benefits estimates derived from expert judgments
(Roman et al., 2008) \341\ as a characterization of uncertainty
regarding the PM2.5-mortality relationship. For the ozone
co-benefits, we present the results as a range reflecting the use of
several different concentration-response functions for mortality, with
the lower end of the range based on a function from Bell et al. (2004)
\342\ and the upper end based on a function from Levy et al.
(2005).\343\ Similar to PM2.5, the range of ozone co-
benefits does not capture the full range of inherent uncertainty.
---------------------------------------------------------------------------
\339\ Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y.
Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the
American Cancer Society Study Linking Particulate Air Pollution and
Mortality. Health Effects Institute. (HEI Research Report number
140). Boston, MA: Health Effects Institute.
\340\ Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012.
``Chronic Exposure to Fine Particles and Mortality: An Extended
Follow-Up of the Harvard Six Cities Study from 1974 to 2009.''
Environmental Health Perspective, 120(7), July, pp. 965-970.
\341\ Roman, H., et al. 2008. ``Expert Judgment Assessment of
the Mortality Impact of Changes in Ambient Fine Particulate Matter
in the U.S.'' Environmental Science & Technology, Vol. 42, No. 7,
February, pp. 2268-2274.
\342\ Bell, M.L., et al. 2004. ``Ozone and Short-Term Mortality
in 95 U.S. Urban Communities, 1987-2000.'' Journal of the American
Medical Association, 292(19), pp. 2372-8.
\343\ Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005.
``Ozone exposure and mortality: an empiric bayes metaregression
analysis.'' Epidemiology. 16(4): p. 458-68.
---------------------------------------------------------------------------
In this analysis, the EPA assumes that the health impact function
for fine particles is without a threshold. This is based on the
conclusions of EPA's Integrated Science Assessment for Particulate
Matter,\344\ which evaluated the substantial body of published
scientific literature, reflecting thousands of epidemiology,
toxicology, and clinical studies that documents the association between
elevated PM2.5
[[Page 34942]]
concentrations and adverse health effects, including increased
premature mortality. This assessment, which was twice reviewed by the
EPA's independent Science Advisory Board, concluded that the scientific
literature consistently finds that a no-threshold model most adequately
portrays the PM-mortality concentration-response relationship.
---------------------------------------------------------------------------
\344\ U.S. Environmental Protection Agency. 2009. Integrated
Science Assessment for Particulate Matter (Final Report). Research
Triangle Park, NC: National Center for Environmental Assessment, RTP
Division. (EPA document number EPA-600-R-08-139F, December).
Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------
In general, we are more confident in the magnitude of the risks we
estimate from simulated PM2.5 concentrations that coincide
with the bulk of the observed PM concentrations in the epidemiological
studies that are used to estimate the benefits. Likewise, we are less
confident in the risk we estimate from simulated PM2.5
concentrations that fall below the bulk of the observed data in these
studies.
For this analysis, policy-specific air quality data are not
available,\345\ and thus, we are unable to estimate the percentage of
premature mortality associated with this specific rule's emission
reductions at each PM2.5 level. As a surrogate measure of
mortality impacts, we provide the percentage of the population exposed
above the lowest measured PM2.5 level (LML) in each of the
studies from which we obtained concentration-response functions for
PM2.5 mortality, using the estimates of PM2.5
from the source apportionment modeling used to calculate the benefit-
per-ton estimates for the EGU sector. Using the Krewski et al. (2009)
study, 93 percent of the population is exposed to annual mean
PM2.5 levels at or above the LML of 5.8 micrograms per cubic
meter ([mu]g/m\3\). Using the Lepeule et al. (2012) study, 67 percent
of the population is exposed above the LML of 8 [mu]g/m\3\. It is
important to note that baseline exposure is only one parameter in the
health impact function, along with baseline incidence rates,
population, and change in air quality. Therefore, caution is warranted
when interpreting the LML assessment for this rule because these
results are not consistent with results from rules that had air quality
modeling.
---------------------------------------------------------------------------
\345\ In addition, site-specific emission reductions will depend
upon how states implement the guidelines.
---------------------------------------------------------------------------
Every benefit analysis examining the potential effects of a change
in environmental protection requirements is limited, to some extent, by
data gaps, model capabilities (such as geographic coverage) and
uncertainties in the underlying scientific and economic studies used to
configure the benefit and cost models. Despite these uncertainties, we
believe the air quality co-benefit analysis for this rule provides a
reasonable indication of the expected health benefits of the air
pollution emission reductions for the illustrative compliance options
for the proposed standards under a set of reasonable assumptions. This
analysis does not include the type of detailed uncertainty assessment
found in the 2012 PM2.5 National Ambient Air Quality
Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air
quality input and monitoring data to conduct a complete benefits
assessment. In addition, using a benefit-per-ton approach adds another
important source of uncertainty to the benefits estimates. The 2012
PM2.5 NAAQS benefits analysis provides an indication of the
sensitivity of our results to various assumptions.
We note that the monetized co-benefits estimates shown here do not
include several important benefit categories, including exposure to
SO2, NOX, and hazardous air pollutants (e.g.,
mercury and hydrogen chloride), as well as ecosystem effects and
visibility impairment. Although we do not have sufficient information
or modeling available to provide monetized estimates for this rule, we
include a qualitative assessment of these unquantified benefits in the
RIA for these proposed amendments.
For more information on the benefits analysis, please refer to the
RIA for this rule, which is available in the rulemaking docket.
XI. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review
Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more or adversely affect in a material
way the economy, a sector of the economy, productivity, competition,
jobs, the environment, public health or safety, or state, local, or
tribal governments or communities. The $100 million threshold can be
triggered by either costs or benefits, or a combination of them.
Accordingly, the EPA submitted this action to OMB for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and
any changes made in response to OMB recommendations have been
documented in the docket for this action.
The EPA also prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
RIA for this proposed rule. A copy of the analysis is available in the
docket for this action.
Consistent with EO 12866 and EO 13563, the EPA estimated the costs
and benefits for illustrative compliance approaches of implementing the
proposed guidelines. This proposal sets goals to reduce CO2
emissions from the electric power industry. Actions taken to comply
with the proposed guidelines will also reduce the emissions of directly
emitted PM2.5, sulfur dioxide (SO2) and nitrogen
oxides (NOX). The benefits associated with these PM,
SO2 and NOX reductions are referred to as co-
benefits, as these reductions are not the primary objective of this
rule.
The EPA has used the social cost of carbon estimates presented in
the 2013 Technical Support Document: Technical Update of the Social
Cost of Carbon for Regulatory Impact Analysis Under Executive Order
12866 (2013 SCC TSD) to analyze CO2 climate impacts of this
rulemaking. We refer to these estimates, which were developed by the
U.S. government, as ``SCC estimates.'' The SCC is an estimate of the
monetary value of impacts associated with a marginal change in
CO2 emissions in a given year. The four SCC estimates are
associated with different discount rates (model average at 2.5 percent
discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent),
and each increases over time. In this summary, the EPA provides the
estimate of climate benefits associated with the SCC value deemed to be
central in the SCC TSD: The model average at 3% discount rate. For the
regional compliance approach, the EPA estimates that in 2020 this
Option 1 proposal will yield monetized climate benefits (in 2011$) of
approximately $17 billion (3 percent model average). The air pollution
health co-benefits in 2020 are estimated to be $16 billion to $37
billion (2011$) for a 3 percent discount rate and $15 billion to $34
billion (2011$) for a 7 percent discount rate. The annual, illustrative
compliance costs estimated by IPM and inclusive of demand side energy
efficiency program and participant costs and MRR costs, are
approximately $5.5 billion (2011$) in 2020. The quantified net benefits
(the difference between monetized benefits and costs) in 2020 are
estimated to be $28 billion to $49 billion assuming a regional
compliance approach (2011$) using a 3 percent discount rate (model
average). This range of net benefits is estimated to be $27 billion to
$50 billion assuming a state compliance approach (2011$)
[[Page 34943]]
using a 3 percent discount rate (model average). Table 18 shows the
climate benefits, health co-benefits, cost and net benefits for Option
1 in 2020 for state and regional compliance approaches. Table 19 shows
similar estimates for 2030.
For Option 1 in 2030 assuming a regional compliance approach, the
EPA estimates this proposal will yield monetized climate benefits (in
2011$) of approximately $30 billion (3 percent, model average). The air
pollution health co-benefits in 2030 are estimated to be $25 billion to
$59 billion (2011$) for a 3 percent discount rate and $23 billion to
$54 billion (2011$) for a 7 percent discount rate. The annual
illustrative compliance costs estimated using IPM, inclusive of a
demand-side energy efficiency program and participant costs and MRR
costs, are approximately $7.3 billion (2011$) in 2030. The quantified
net benefits (the difference between monetized benefits and costs) in
2030 are estimated to be $48 billion to $82 billion (2011$) using a 3
percent discount rate (model average). The EPA estimates that this
proposal will yield monetized climate benefits (in 2011$) of
approximately $31 billion (3 percent, model average) for Option 1 state
compliance approach in 2030. The air pollution health co-benefits in
2030 are estimated to be $27 billion to $62 billion (2011$) for a 3
percent discount rate and $24 billion to $56 billion (2011$) for a 7
percent discount rate. The annual illustrative compliance costs
estimated using IPM, inclusive of demand side energy efficiency program
and participant costs and MRR costs, are approximately $8.8 billion
(2011$) in 2030. The quantified net benefits (the difference between
monetized benefits and costs) in 2030 are estimated to be $49 billion
to $84 billion (2011$) using a 3 percent discount rate (model average)
assuming a state compliance approach. Based upon the foregoing
discussion, it remains clear that the benefits of the proposal Option 1
are substantial and far exceed the costs.
Table 18--Summary of the Monetized Benefits, Compliance Costs and Net
Benefits for Proposed Option 1 in 2020 \a\
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $17.
------------------------------------------
Air pollution health co- $16 to $37...... $15 to $34
benefits \c\.
Total Compliance Costs \d\... $5.5............ $5.5
Net Monetized Benefits \e\... $28 to $49...... $26 to $45
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.3 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $18.
------------------------------------------
Air pollution health co- $17 to $40...... $15 to $36
benefits \c\.
Total Compliance Costs \d\... $7.5............ $7.5
Net Monetized Benefits \e\... $27 to $50...... $26 to $46
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.5 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3 percent
discount rate; however, we emphasize the importance and value of
considering the full range of SCC values. As shown in the RIA, climate
benefits are also estimated using the other three SCC estimates (model
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
percentile at 3 percent). The SCC estimates are year-specific and
increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed option
and a discount rate of approximately 5 percent. This estimate includes
monitoring, recordkeeping, and reporting costs and demand side energy
efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
Table 19--Summary of the Monetized Benefits, Compliance Costs, and Net
Benefits for Proposed Option 1 in 2030 \a\
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $30.
------------------------------------------------------------------------
Air pollution health co- $25 to $59...... $23 to $54
benefits \c\.
Total Compliance Costs \d\... $7.3............ $7.3
Net Monetized Benefits \e\... $48 to $82...... $46 to $77
------------------------------------------------------------------------
[[Page 34944]]
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.7 tons of Hg and 580 tons of HCl.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $31.
------------------------------------------
Air pollution health co- $27 to $62...... $24 to $56
benefits \c\.
Total Compliance Costs \d\... $8.8............ $8.8
Net Monetized Benefits \e\... $49 to $84...... $46 to $79
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
2.1 tons of Hg and 590 tons of HCl.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2030, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3 percent
discount rate; however, we emphasize the importance and value of
considering the full range of SCC values. As shown in the RIA, climate
benefits are also estimated using the other three SCC estimates (model
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
percentile at 3 percent). The SCC estimates are year-specific and
increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed option
and a discount rate of approximately 5 percent. This estimate includes
monitoring, recordkeeping, and reporting costs and demand side energy
efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
The estimated costs and benefits for the regulatory alternative--
Option 2 regional and state compliance approaches are shown in Tables
20 and 21. As these tables reflect, net benefits in 2020 are estimated
to be $22 to $40 billion (3 percent discount rate) and $21 to $37
billion (7 percent discount rate) for Option 2 assuming regional
compliance. These Option 2 net benefit estimates become $22 to $40
billion (3 percent discount rate) and $20 to $37 billion (7 percent
discount rate) with the state compliance approach. In 2025, net
benefits are estimated to be $31 billion to $54 billion (3 percent
discount rate) and $29 billion to $50 billion (7 percent discount rate)
assuming a regional compliance approach and $31 billion to $55 billion
(3 percent discount rate) and $29 billion to $51 billion (7 percent
discount rate) assuming a state compliance approach.
The EPA could not monetize important benefits of proposed Option 1
and regulatory alternative Option 2. Unquantified benefits include
climate benefits from reducing emissions of non-CO2
greenhouse gases and co-benefits from reducing exposure to
SO2, NOX, and hazardous air pollutants (e.g.,
mercury and hydrogen chloride), as well as ecosystem effects and
visibility impairment.
Table 20--Summary of the Monetized Benefits, Compliance Costs, and Net
Benefits for Proposed Option 2 in 2020 a
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $13.
------------------------------------------
Air pollution health co- $13 to $31...... $12 to $28
benefits \c\.
Total Compliance Costs \d\... $4.3............ $4.3
Net Monetized Benefits \e\... $22 to $40...... $21 to $37
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
0.9 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
[[Page 34945]]
Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $14.
------------------------------------------------------------------------
Air pollution health co- $14 to $32...... $12 to $29
benefits \c\.
Total Compliance Costs \d\... $5.5............ $5.5
Net Monetized Benefits \e\... $22 to $40...... $20 to $37
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.2 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3 percent
discount rate; however, we emphasize the importance and value of
considering the full range of SCC values. As shown in the RIA, climate
benefits are also estimated using the other three SCC estimates (model
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
percentile at 3 percent). The SCC estimates are year-specific and
increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed option
and a discount rate of approximately 5 percent. This estimate includes
monitoring, recordkeeping and reporting costs and demand side energy
efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
Table 21--Summary of the Monetized Benefits, Compliance Costs, and Net
Benefits for Proposed Option 2 in 2025 a
[Billions of 2011$]
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
------------------------------------------------------------------------
Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $18.
------------------------------------------
Air pollution health co- $17 to $40...... $16 to $36
benefits \c\.
Total Compliance Costs \d\... $4.5............ $4.5
Net Monetized Benefits \e\... $31 to $54...... $29 to $50
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.3 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\......... $19.
------------------------------------------
Air pollution health co- $18 to $41...... $16 to $37
benefits \c\.
Total Compliance Costs \d\... $5.5............ $5.5
Net Monetized Benefits \e\... $31 to $55...... $29 to $51
------------------------------------------------------------------------
Non-monetized Benefits....... Direct exposure to SO2 and NO2.
1.7 tons of Hg.
Ecosystem Effects.
Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2025, and are rounded to two significant
figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
impacts from CO2 emission changes and does not account for changes in
non-CO2 GHG emissions. Also, different discount rates are applied to
SCC than to the other estimates because CO2 emissions are long-lived
and subsequent damages occur over many years. The benefit estimates in
this table are based on the average SCC estimated for a 3 percent
discount rate; however, we emphasize the importance and value of
considering the full range of SCC values. As shown in the RIA, climate
benefits are also estimated using the other three SCC estimates (model
average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
percentile at 3 percent). The SCC estimates are year-specific and
increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
PM2.5 and ozone associated with emission reductions of directly
emitted PM2.5, SO2 and NOX. The range reflects the use of
concentration-response functions from different epidemiology studies.
The reduction in premature fatalities each year accounts for over 90
percent of total monetized co-benefits from PM2.5 and ozone. These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to allow differentiation
of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
estimated using the Integrated Planning Model for the proposed option
and a discount rate of approximately 5 percent. This estimate includes
monitoring, recordkeeping and reporting costs and demand side energy
efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
using the global social cost of carbon at a 3 percent discount rate
(model average). The RIA includes combined climate and health
estimates based on these additional discount rates.
The analysis done in support of this proposal shows that the
emission reductions, benefits, and costs for the illustrative
compliance approaches for the proposed Option 1 (and regulatory
alternative Option 2) are larger if states choose to comply on an
individual basis, compared to the illustrative regional compliance
approach. The regional approach allows for more flexibility across
states, which results in slightly fewer emission reductions and
[[Page 34946]]
lower overall costs. Net benefits (the difference between benefits and
costs) are roughly equivalent under the regional and state compliance
approaches.
In evaluating the impacts of the proposed guidelines, we analyzed a
number of uncertainties, for example evaluating different potential
spatial approaches to state compliance (i.e., state and regional) and
in the estimated benefits of reducing carbon dioxide and other air
pollutants. For a further discussion of key evaluations of uncertainty
in the regulatory analyses for this proposed rulemaking, see the RIA
included in the docket.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by the EPA has
been assigned the EPA ICR number 2503.01.
The information collection requirements are based on the
recordkeeping and reporting burden associated with developing,
implementing, and enforcing a state plan to limit CO2
emissions from existing sources in the power sector. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to agency
policies set forth in 40 CFR part 2, subpart B.
The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation of this
proposed action) is estimated to be a range of 316,217 hours at a total
annual labor cost of $22,381,044, to 633,001 hours at a total annual
labor cost of $44,802,243. The lower bound estimate reflects the
assumption that some states already have energy efficiency and
renewable energy programs in place. The higher bound estimate reflects
the assumption that no states have energy efficiency and renewable
energy programs in place. The total annual burden for the federal
government (averaged over the first 3 years following promulgation of
this proposed action) is estimated to be 53,300 hours at a total annual
labor cost of $2,958,005. Burden means the total time, effort, or
financial resources expended by persons to generate, maintain, retain,
or disclose or provide information to or for a federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID Number EPA-HQ-
OAR-2013-0602. Submit any comments related to the ICR to the EPA and to
OMB. See the ADDRESSES section at the beginning of this notice for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after June 18, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by July 18, 2014.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small
entities, small entity is defined as:
(1) A small business that is defined by the SBA's regulations at 13
CFR 121.201 (for the electric power generation industry, the small
business size standard is an ultimate parent entity with less than 750
employees. The NAICS codes for the affected industry are in Table 22
below);
(2) A small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
(3) A small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.
Table 22--Potentially Regulated Categories and Entities a
----------------------------------------------------------------------------------------------------------------
NAICS
Category Code Examples of potentially regulated entities \a\
----------------------------------------------------------------------------------------------------------------
Industry....................... 221112 Fossil fuel electric power generating units.
State/Local Government......... 221112 b Fossil fuel electric power generating units owned by municipalities.
----------------------------------------------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate electric power generating units
(includes boilers and stationary combined cycle combustion turbines).
\b\ State or local government-owned and operated establishments are classified according to the activity in
which they are engaged.
After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
The proposed rule will not impose any requirements on small
entities. Specifically, emission guidelines
[[Page 34947]]
established under CAA section 111(d) do not impose any requirements on
regulated entities and, thus, will not have a significant economic
impact upon a substantial number of small entities. After emission
guidelines are promulgated, states establish standards on existing
sources, and it is those state requirements that could potentially
impact small entities. Our analysis here is consistent with the
analysis of the analogous situation arising when the EPA establishes
NAAQS, which do not impose any requirements on regulated entities. As
here, any impact of a NAAQS on small entities would only arise when
states take subsequent action to maintain and/or achieve the NAAQS
through their state implementation plans. See American Trucking Assoc.
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have
significant impacts upon small entities because NAAQS themselves impose
no regulations upon small entities).
Nevertheless, the EPA is aware that there is substantial interest
in the proposed rule among small entities (municipal and rural electric
cooperatives). As detailed in Section III.A of this preamble, the EPA
has conducted an unprecedented amount of stakeholder outreach on
setting emission guidelines for existing EGUs. While formulating the
provisions of the proposed rule, the EPA considered the input provided
over the course of the stakeholder outreach. Section III.B of this
preamble describes the key messages from stakeholders. In addition, as
described in the RFA section of the preamble to the proposed standards
of performance for GHG emissions from new EGUs (79 FR 1499-1500,
January 8, 2014), the EPA conducted outreach to representatives of
small entities while formulating the provisions of the proposed
standards. Although only new EGUs would be affected by those proposed
standards, the outreach regarded planned actions for new and existing
sources. We invite comments on all aspects of the proposal and its
impacts, including potential impacts on small entities.
D. Unfunded Mandates Reform Act
This proposed action does not contain a federal mandate that may
result in expenditures of $100 million or more for state, local, and
tribal governments, in the aggregate, or the private sector in any one
year. Specifically, the emission guidelines proposed under CAA section
111(d) do not impose any direct compliance requirements on regulated
entities, apart from the requirement for states to develop state plans.
The burden for states to develop state plans in the 3-year period
following promulgation of the rule was estimated and is listed in
Section IX B., above, but this burden is estimated to be below $100
million in any one year. Thus, this proposed rule is not subject to the
requirements of section 202 or section 205 of the Unfunded Mandates
Reform Act (UMRA).
This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments.
In light of the interest among governmental entities, the EPA
initiated consultations with governmental entities while formulating
the provisions of the proposed standards for new EGUs. Although only
new EGUs would be affected by those proposed standards, the outreach
regarded planned actions for new and existing sources. As described in
the UMRA discussion in the preamble to the proposed standards of
performance for GHG emissions from new EGUs (79 FR 1500-1501, January
8, 2014), the EPA consulted with the following 10 national
organizations representing state and local elected officials: (1)
National Governors Association; (2) National Conference of State
Legislatures, (3) Council of State Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6) National Association of
Counties, (7) International City/County Management Association, 8)
National Association of Towns and Townships, (9) County Executives of
America, and 10) Environmental Council of States. On February 26, 2014,
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and
emission standards for modified and reconstructed EGUs.
While formulating the provisions of these proposed emission
guidelines, the EPA also considered the input provided over the course
of the extensive stakeholder outreach conducted by the EPA (see
Sections III.A. and III.B. of this preamble).
E. Executive Order 13132, Federalism
Under Executive Order 13132, the EPA may not issue an action that
has federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the federal
government provides the funds necessary to pay the direct compliance
costs incurred by state and local governments, or the EPA consults with
state and local officials early in the process of developing the
proposed action.
The EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs. As discussed in the
Supporting Statement found in the docket for this rulemaking, the
development of state plans will entail many hours of staff time to
develop and coordinate programs for compliance with the proposed rule,
as well as time to work with state legislatures as appropriate, and
develop a plan submittal.
The EPA consulted with state and local officials early in the
process of developing the proposed action to permit them to have
meaningful and timely input into its development. As described in the
Federalism discussion in the preamble to the proposed standards of
performance for GHG emissions from new EGUs (79 FR 1501, January 8,
2014), the EPA consulted with state and local officials in the process
of developing the proposed standards for newly constructed EGUs. This
outreach regarded planned actions for new, reconstructed, modified and
existing sources. The EPA invited the following 10 national
organizations representing state and local elected officials to a
meeting on April 12, 2011, in Washington DC: (1) National Governors
Association; (2) National Conference of State Legislatures, (3) Council
of State Governments, (4) National League of Cities, (5) U.S.
Conference of Mayors, (6) National Association of Counties, (7)
International City/County Management Association, (8) National
Association of Towns and Townships, (9) County Executives of America,
and (10) Environmental Council of States. These 10 organizations
representing elected state and local officials have been identified by
the EPA as the ``Big 10'' organizations appropriate to contact for
purpose of consultation with elected officials. On February 26, 2014,
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and
emission standards for modified and reconstructed EGUs. In addition,
extensive stakeholder outreach conducted by the EPA allowed state
leaders, including governors, environmental commissioners, energy
officers, public utility commissioners, and air directors,
opportunities to engage with EPA officials and provide input regarding
reducing carbon pollution from power plants.
A detailed Federalism Summary Impact Statement (FSIS) describing
the
[[Page 34948]]
most pressing issues raised in pre-proposal and post-proposal comments
will be forthcoming with the final rule, as required by section 6(b) of
Executive Order 13132. In the spirit of Executive Order 13132, and
consistent with the EPA's policy to promote communications between the
EPA and state and local governments, the EPA specifically solicits
comment on this proposed action from State and local officials.
F. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It would not
impose substantial direct compliance costs on tribal governments that
have affected EGUs located in their area of Indian country. Tribes are
not required to, but may, develop or adopt CAA programs. Tribes are not
required to develop plans to implement the guidelines under CAA section
111(d) for affected EGUs. To the extent that a tribal government seeks
and attains treatment in a manner similar to a state (TAS) status for
that purpose and is delegated authority for air quality planning
purposes, these proposed emission guidelines would require that
planning requirements be met and emission management implementation
plans be executed by the tribes. The EPA is aware of three coal-fired
EGUs and one natural gas-fired EGU located in Indian country but is not
aware of any affected EGUs that are owned or operated by tribal
entities. The EPA notes that this proposal does not directly impose
specific requirements on EGU sources, including those located in Indian
country, such as the three coal-fired EGUs and one natural gas-fired
EGU, but provides guidance to any tribe with delegated authority to
address CO2 emissions from EGU sources found subject to
section 111(d) of the CAA. Thus, Executive Order 13175 does not apply
to this action.
The EPA conducted outreach to tribal environmental staff and
offered consultation with tribal officials in developing this action.
Because the EPA is aware of tribal interest in this proposed rule,
prior to the April 13, 2012 proposal (77 FR 22392-22441), the EPA
offered consultation with tribal officials early in the process of
developing the proposed regulation to permit them to have meaningful
and timely input into its development. The EPA's consultation regarded
planned actions for new and existing sources. In addition, on April 15,
2014, prior to proposal, the EPA met with Navajo Energy Development
Group officials. For this proposed action for existing EGUs, a tribe
that has one or more affected EGUs located in its area of Indian
country \346\ would have the opportunity, but not the obligation, to
establish a CO2 performance standard and a CAA section
111(d) plan for its area of Indian country.
---------------------------------------------------------------------------
\346\ The EPA is aware of at least four affected EGUs located in
Indian country: Two on Navajo lands, the Navajo Generating Station
and the Four Corners Generating Station; one on Ute lands, the
Bonanza Generating Station; and one on Fort Mojave lands, the South
Point Energy Center. The affected EGUs at the first three plants are
coal-fired EGUs. The fourth affected EGU is an NGCC facility.
---------------------------------------------------------------------------
Consultation letters were sent to 584 tribal leaders. The letters
provided information regarding the EPA's development of both the NSPS
and emission guidelines for fossil fuel-fired EGUs and offered
consultation. No tribes have requested consultation. Tribes were
invited to participate in the national informational webinar held
August 27, 2013. In addition, a consultation/outreach meeting was held
on September 9, 2013, with tribal representatives from some of the 584
tribes. The EPA also met with tribal environmental staff via National
Tribal Air Association teleconferences on July 25, 2013, and December
19, 2013. In those teleconferences, the EPA provided background
information on the GHG emission guidelines to be developed and a
summary of issues being explored by the agency. Tribes have expressed
varied points of view. Some tribes raised concerns about the impacts of
the regulations on EGUs and the subsequent impact on jobs and revenue
for their tribes. Other tribes expressed concern about the impact the
regulations would have on the cost of water to their communities as a
result of increased costs to the EGU that provide energy to transport
the water to the tribes. Other tribes raised concerns about the impacts
of climate change on their communities, resources, life ways and
hunting and treaty rights. The tribes were also interested in the scope
of the guidelines being considered by the agency (e.g., over what time
period, relationship to state and multi-state plans) and how tribes
will participate in these planning activities. In addition, the EPA
held a series of listening sessions prior to development of this
proposed action. In 2013, tribes participated in a session with the
state agencies, as well as a separate session with tribes.
During the public comment period for this proposal, the EPA will
hold meetings with tribal environmental staff to inform them of the
content of this proposal, as well as offer further consultation with
tribal elected officials where it is appropriate. We specifically
solicit comment from tribal officials on this proposed rule.
G. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as
applying to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the Order
has the potential to influence the regulation. This action is not
subject to EO 13045 because it does not involve decisions on
environmental health or safety risks that may disproportionately affect
children. The EPA believes that the CO2 emission reductions
resulting from implementation of the proposed guidelines, as well as
substantial ozone and PM2.5 emission reductions as a co-
benefit, would further improve children's health.
H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355; May 22, 2001) requires the EPA
to prepare and submit a Statement of Energy Effects to the
Administrator of the Office of Information and Regulatory Affairs, OMB,
for actions identified as ``significant energy actions.'' This action,
which is a significant regulatory action under EO 12866, is likely to
have a significant effect on the supply, distribution, or use of
energy. We have prepared a Statement of Energy Effects for this action
as follows. We estimate a 4 to 7 percent increase in retail electricity
prices, on average, across the contiguous U.S. in 2020, and a 16 to 22
percent reduction in coal-fired electricity generation as a result of
this rule. The EPA projects that electric power sector delivered
natural gas prices will increase by about 8 to 12 percent in 2020. For
more information on the estimated energy effects, please refer to the
economic impact analysis for this proposal. The analysis is available
in the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use Voluntary Census Standards (VCS) in its regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or
[[Page 34949]]
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs the EPA to provide
Congress, through annual reports to OMB, with explanations when an
agency does not use available and applicable VCS. This proposed
rulemaking does not involve technical standards.
The EPA welcomes comments on this aspect of the proposed rulemaking
and specifically invites the public to identify potentially-applicable
VCS and to explain why such standards should be used in this action.
J. Executive Order 12898: Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the U.S.
Section II.A of this preamble summarizes the public health and
welfare impacts from GHG emissions that were detailed in the 2009
Endangerment Finding under CAA section 202(a)(1).\347\ As part of the
Endangerment Finding, the Administrator considered climate change risks
to minority or low-income populations, finding that certain parts of
the population may be especially vulnerable based on their
circumstances. These include the poor, the elderly, the very young,
those already in poor health, the disabled, those living alone, and/or
indigenous populations dependent on one or a few resources. The
Administrator placed weight on the fact that certain groups, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects.
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\347\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66,496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------
Strong scientific evidence that the potential impacts of climate
change raise environmental justice issues is found in the major
assessment reports by the U.S. Global Change Research Program (USGCRP),
the Intergovernmental Panel on Climate Change (IPCC), and the National
Research Council (NRC) of the National Academies, summarized in the
record for the Endangerment Finding. Their conclusions include that
poor communities can be especially vulnerable to climate change impacts
because they tend to have more limited adaptive capacities and are more
dependent on climate-sensitive resources such as local water and food
supplies. In addition, Native American tribal communities possess
unique vulnerabilities to climate change, particularly those on
established reservations that are restricted to reservation boundaries
and therefore have limited relocation options. Tribal communities whose
health, economic well-being, and cultural traditions depend upon the
natural environment will likely be affected by the degradation of
ecosystem goods and services associated with climate change. Southwest
native cultures are especially vulnerable to water quality and
availability impacts. Native Alaskan communities are likely to
experience disruptive impacts, including shifts in the range or
abundance of wild species crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific
understanding of climate change risks to minority and low-income
populations.
This proposed rule would limit GHG emissions by establishing
CO2 emission guidelines for existing fossil fuel-fired EGUs.
In addition to reducing CO2 emissions, implementing the
proposed rule would reduce other emissions from EGUs that become
dispatched less frequently due to their relatively low energy
efficiency. These emission reductions will include SO2 and
NOx, which form ambient PM2.5 and ozone in the atmosphere,
and hazardous air pollutants (HAP), such as mercury and hydrochloric
acid. In the final rule revising the annual PM2.5
NAAQS,\348\ the EPA identified persons with lower socioeconomic status
as an at-risk population for experiencing adverse health effects
related to PM exposures. Persons with lower socioeconomic status have
been generally found to have a higher prevalence of pre-existing
diseases, limited access to medical treatment, and increased
nutritional deficiencies, which can increase this population's risk to
PM-related and ozone-related effects.\349\ Therefore, in areas where
this rulemaking reduces exposure to PM2.5, ozone, and
methylmercury, persons with low socioeconomic status would also
benefit. The RIA for this rulemaking, included in the docket for this
rulemaking, provides additional information regarding the health and
ecosystem effects associated with these emission reductions.
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\348\ ``National Ambient Air Quality Standards for Particulate
Matter, Final Rule,'' 78 FR 3086 (Jan. 15, 2013).
\349\ U.S. Environmental Protection Agency (U.S. EPA). 2009.
Integrated Science Assessment for Particulate Matter (Final Report).
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP
Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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While there will be many locations with improved air quality for
PM2.5, ozone, and HAP, there may also be EGUs whose
emissions of one or more of these pollutants or their precursors
increase as a result of the proposed emission guidelines for existing
fossil fuel-fired EGUs. This may occur at EGUs that become dispatched
more intensively than in the past because they become more energy
efficient. The EPA has considered the potential for such increases and
the environmental justice implications of such increases.
As we noted in the NSR discussion in this preamble, as part of a
state's CAA section 111(d) plan, the state may require an affected EGU
to undertake a physical or operational changes to improve the unit's
efficiency that result in an increase in the unit's dispatch and an
increase in the unit's annual emissions of GHGs and/or other regulated
pollutants. A state can take steps to avoid increased utilization of
particular EGUs and thus avoid any significant increases in emissions
including emissions of other regulated pollutants whose environmental
effects would be more localized around the affected EGU. To the extent
that states take this path, there would be no new environmental justice
concerns in the areas near such EGUs. For any EGUs that make
modifications that do trigger NSR permitting, the applicable local,
state, or federal permitting program will ensure that there are no new
NAAQS violations and that no existing NAAQS violations are made worse.
For those EGUs in a permitting situation for which the EPA is the
permit reviewing authority, the EPA will consider environmental justice
issues as required by Executive Order 12898.
In addition to some EGUs possibly being required by a state to make
modifications for increased energy efficiency, another effect of the
proposed CO2 emission guidelines for existing fossil fuel-
fired EGUs would be
[[Page 34950]]
increased utilization of other, unmodified EGUs with relatively low GHG
emissions per unit of electrical output, in particular high efficiency
gas-fired EGUs. Because such EGUs would not have been modified
physically nor changed their method of operation, they would not be
subject to review in the NSR permitting program. Such plants would have
more hours in the year in which they operate and emit pollutants,
including pollutants whose environmental effects if any would be
localized rather than global as is the case with GHG emissions. Changes
in utilization already occur now as demands for and sources of
electrical energy evolve, but the proposed CO2 emission
guidelines for existing fossil fuel-fired EGUs can be expected to cause
more such changes. Because gas-fired EGUs emit essentially no mercury,
increased utilization would not increase methylmercury concentrations
in their vicinities. Increased utilization generally would not cause
higher peak concentrations of PM2.5, NOx, or ozone around
such EGUs than is already occurring because peak hourly or daily
emissions generally would not change, but increased utilization may
make periods of relatively high concentrations more frequent. It should
be noted that the gas-fired sources that are likely to become
dispatched more frequently than at present have very low emissions of
primary particulate matter, SO2 and HAP per unit of
electrical output, such that local (or regional) air quality for these
pollutants is likely to be affected very little. For natural gas-fired
EGUS, the EPA found that regulation of HAP emissions ``is not
appropriate or necessary because the impacts due to HAP emissions from
such units are negligible based on the results of the study documented
in the utility RTC.'' \350\ In studies done by DOE/NETL comparing cost
and performance of coal- and NG-fired generation, they assumed
SO2, PM (and Hg) emissions to be ``negligible.'' Their
studies predict NOx emissions from a NGCC unit to be approximately 10
times lower than a subcritical or supercritical coal-fired boiler. Many
are also very well controlled for emission of NOx through the
application of after combustion controls such as selective catalytic
reduction, although not all gas-fired sources are so equipped.
Depending on the specificity of the state CAA section 111(d) plan, the
state may be able to predict which EGUs and communities may be in this
type of situation and to address any concerns about localized
NO2 concentrations in the design of the CAA section 111(d)
program, or separately from the CAA section 111(d) program but before
its implementation. In any case, existing tracking systems will allow
states and the EPA to be aware of the EGUs whose utilization has
increased most significantly, and thus to be able to prioritize our
efforts to assess whether air quality has changed in the communities in
the vicinity of such EGUs. There are multiple mechanisms in the CAA to
address situations in which air quality has degraded significantly. In
conclusion, this proposed rule would result in regional and national
pollutant reductions; however, there likely would also be some
locations with more times during the year of relatively higher
concentrations of pollutants with potential for effects on localized
communities than would be experienced in the absence of the proposed
rule. The EPA cannot exactly predict how emissions from specific EGUs
would change as an outcome of the proposed rule due to the state-led
implementation. Therefore, the EPA has concluded that it is not
practicable to determine whether there would be disproportionately high
and adverse human health or environmental effects on minority, low
income, or indigenous populations from this proposed rule.
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\350\ 65 FR 79831.
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In order to provide opportunities for meaningful involvement early
on in the rule making process, the EPA has hosted webinars and
conference calls on August 27, 2013, and September 9, 2013, on the
proposed rule specifically for environmental justice communities and
has taken all comments and suggestions into consideration in the design
of the emission guidelines.
The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of exposure to the pollutants
addressed by this proposal.
XII. Statutory Authority
The statutory authority for this action is provided by sections
111, 301, 302, and 307(d)(1)(V) of the CAA, as amended (42 U.S.C. 7411,
7601, 7602, 7607(d)(1)(V)). This action is also subject to section
307(d) of the CAA (42 U.S.C. 7607(d)).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.
Dated: June 2, 2014.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, part
60 of the Code of the Federal Regulations is proposed to be amended as
follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for Part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
2. Section 60.27 is amended by revising paragraph (b) to read as
follows:
Sec. 60.27 Actions by the Administrator.
* * * * *
(b) After receipt of a plan or plan revision, the Administrator
will propose the plan or revision for approval or disapproval. The
Administrator will, within four months after the date required for
submission of a plan or plan revision, approve or disapprove such plan
or revision or each portion thereof, except as provided in Sec.
60.5715.
* * * * *
0
3. Add subpart UUUU to read as follows:
Subpart UUUU: Emission Guidelines for Greenhouse Gas Emissions and
Compliance Times for Electric Utility Generating Units
Sec.
Introduction
60.5700 What is the purpose of this subpart?
60.5705 What pollutants are regulated by this subpart?
60.5710 Am I affected by this subpart?
60.5715 What is the review and approval process for my state plan?
60.5720 What if I do not submit a plan or my plan is not approvable?
60.5725 In lieu of a state plan submittal, are there other
acceptable option(s) for a state to meet its section 111(d)
obligations?
60.5730 Is there an approval process for a negative declaration
letter?
60.5735 What authorities will not be delegated to state, local, or
tribal agencies?
State Plan
60.5740 What must I include in my state plan?
60.5745 Can I work with other states to develop a multi-state plan?
60.5750 Can I include existing requirements, programs, and measures
in my state plan?
60.5755 What are the timing requirements for submitting my state
plan?
60.5760 What must I include in an initial submittal in lieu of a
complete state plan?
[[Page 34951]]
60.5765 What are the state rate-based CO2 emission
performance goals?
60.5770 What is the procedure for converting my state rate-based
CO2 emission performance goal to a mass-based
CO2 emissions performance goal?
60.5775 What schedules, performance periods, and compliance periods
must I include in my state plan?
60.5780 What emission standards and enforcing measures must I
include in my plan?
60.5785 What is the procedure for revising my state plan?
Applicability of State Plans to Affected EGUs
60.5790 Does this subpart directly affect EGU owners and operators
in my state?
60.5795 What affected EGUs must I address in my state plan?
60.5800 What affected EGUs are exempt from my state plan?
60.5805 What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my state plan for affected
EGUs?
Recordkeeping and Reporting Requirements
60.5810 What are my state recordkeeping requirements?
60.5815 What are my state reporting requirements?
Definitions
60.5820 What definitions apply to this subpart?
Table 1 to Subpart UUUU of Part 60--State Rate-based CO2
Emission Performance Goals (Pounds of CO2 Per Net MWh)
Introduction
Sec. 60.5700 What is the purpose of this subpart?
This subpart establishes emission guidelines and approval criteria
for state plans that establish emission standards limiting the control
of greenhouse gas emissions from an affected steam generating unit,
integrated gasification combined cycle (IGCC), or stationary combustion
turbine. An affected steam generating unit, IGCC, or stationary
combustion turbine shall, for the purposes of this subpart, be referred
to as an affected EGU. These emission guidelines are developed in
accordance with sections 111(d) of the Clean Air Act and subpart B of
this part. To the extent any requirement of this subpart is
inconsistent with the requirements of subparts A or B of this part, the
requirements of this subpart will apply.
Sec. 60.5705 What pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases.
(b) The greenhouse gas regulated by this subpart is carbon dioxide
(CO2).
Sec. 60.5710 Am I affected by this subpart?
If you are the Administrator of an air quality program in a state
with one or more affected EGUs that commenced construction on or before
January 8, 2014, you must submit a state plan to the U.S. Environmental
Protection Agency (EPA) that implements the emission guidelines
contained in this subpart. You must submit a negative declaration
letter in place of the state plan if there are no affected EGUs for
which construction commenced on or before January 8, 2014 in your
state.
Sec. 60.5715 What is the review and approval process for my state
plan?
The EPA will review your state plan according to Sec. 60.27 except
that under Sec. 60.27(b) the Administrator will have twelve months
after the date required for submission of a plan or plan revision to
approve or disapprove such plan or revision or each portion thereof. If
you submit a request for extension under Sec. 60.5760(a) in lieu of a
complete state plan the EPA will follow the procedure in Sec.
60.5760(b).
Sec. 60.5720 What if I do not submit a plan or my plan is not
approvable?
If you do not submit an approvable state plan the EPA will develop
a Federal plan for your state according to Sec. 60.27 to implement the
emission guidelines contained in this subpart. Owners and operators of
affected entities not covered by an approved state plan must comply
with a Federal plan implemented by the EPA for the state. The Federal
plan is an interim action and will be automatically withdrawn when your
state plan is approved.
Sec. 60.5725 In lieu of a state plan submittal, are there other
acceptable option(s) for a state to meet its section 111(d)
obligations?
A state may meet its CAA section 111(d) obligations only by
submitting a complete state plan or a negative declaration letter (if
applicable).
Sec. 60.5730 Is there an approval process for a negative declaration
letter?
No. The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received, the
EPA will place a copy in the public docket and publish a notice in the
Federal Register. If, at a later date, an affected EGU for which
construction commenced on or before January 8, 2014 is found in your
state, a Federal plan implementing the emission guidelines contained in
this subpart would automatically apply to that affected EGU until your
state plan is approved.
Sec. 60.5735 What authorities will not be delegated to state, local,
or tribal agencies?
The authorities that will not be delegated to State, local, or
tribal agencies are specified in paragraph (a) of this section.
(a) Approval of alternatives, not already approved by this subpart,
to the emissions performance goals in Table 1 to this subpart
established under Sec. 60.5755.
(b) [Reserved]
State Plan
Sec. 60.5740 What must I include in my state plan?
(a) You must include the elements described in paragraphs (a)(1)
through (11) of this section in your state plan.
(1) Identification of affected entities, including an inventory of
CO2 emissions from affected EGUs during the most recent
calendar year prior to the submission of the plan for which data is
available.
(2) A description of plan approach and the geographic scope of a
plan (state or multi-state), including, if relevant, identification of
multi-state plan participants and geographic boundaries related to plan
elements.
(3) Identification of the state emission performance level for
affected entities that will be achieved through implementation of the
plan.
(i) The plan must specify the average emissions performance that
the plan will achieve for the following periods:
(A) The 10 year interim plan performance period of 2020 through
2029.
(B) The single projection year of 2030.
(ii) The identified emission performance level for each plan
performance period in paragraph (a)(3)(i) of this section must be
equivalent to or better than the levels of the rate-based
CO2 emission performance goals in Table 1 of this Subpart
for affected entities in your state. The emission performance levels
may be in either a rate-based form or a mass based form which is
calculated according to Sec. 60.5770. The CO2 emission
performance level specified must include either of the following as
applicable:
(A) For a rate-based CO2 emission performance level, the
identified level must represent the CO2 emissions rate, in
pounds of CO2 per MWh of net energy output that will be
achieved by affected entities.
(B) For a mass-based CO2 emission performance level, the
identified level of performance must represent the total tons of
CO2 that will be emitted by affected entities during each
plan performance period.
[[Page 34952]]
(iii) For the interim plan performance period you must identify the
emission performance levels anticipated under the plan during each year
2020 through 2029.
(4) A demonstration that the plan is projected to achieve each of
the state's emission performance levels for affected entities according
to paragraph (a)(3) of this section.
(5) Identification of emission standards for each affected entity,
compliance periods for each emission standard, and demonstration that
the emission standards are, when taken together, sufficiently
protective to meet the state emissions performance level.
(6) A demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable with respect to
an affected entity.
(7) If your state plan does not require achievement of the full
level of required emission performance, and the identified interim
increments of performance in paragraph (a)(3)(iii) of this section,
through emission limits on EGUs, the plan must specify the following:
(i) Program implementation milestones (e.g., start of an end-use
energy efficiency program, retirement of an affected EGU, or increase
in portfolio requirements under a renewable portfolio standard) and
milestone dates that are appropriate to the requirements, programs, and
measures included in the plan.
(ii) Corrective measures that will be implemented in the event that
the comparison required by Sec. 60.5815(b) of projected versus actual
emissions performance of affected entities shows that actual emissions
performance is greater than 10 percent in excess to projected plan
performance for the period described in Sec. 60.5775(c)(1), and a
process and schedule for implementing such corrective measures.
(8) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each affected entity. If applicable,
these requirements must be consistent with the requirements specified
in Sec. 60.5810.
(9) Description of the process, contents, and schedule for annual
state reporting to the EPA about plan implementation and progress
including information required under Sec. 60.5815.
(10) Certification that the hearing on the state plan was held, a
list of witnesses and their organizational affiliations, if any,
appearing at the hearing, and a brief written summary of each
presentation or written submission.
(11) Supporting material including:
(i) Materials demonstrating the state's legal authority to carry
out each component of its plan, including emissions standards;
(ii) Materials supporting the projected emissions performance level
that will be achieved by affected entities under the plan, according to
paragraph (a)(4) of this section;
(iii) Materials supporting the projected mass-based emission
performance goal, calculated pursuant to Sec. 60.5770, if applicable;
and
(iv) Materials necessary to support evaluation of the plan by the
EPA.
(b) You must follow the requirements of subpart B of this part
(Adoption and Submittal of state plans for Designated Facilities) and
demonstrate that they were met in your state plan.
Sec. 60.5745 Can I work with other states to develop a multi-state
plan?
A multi-state plan may be submitted, provided it is signed by
authorized officials for each of the states participating in the multi-
state plan. In this instance, the joint submittal will have the same
legal effect as an individual submittal for each participating state. A
multi-state plan will include all the required elements for a single-
state plan specified in Sec. 60.5740(a). A multi-state plan, if
submitted by a state, must:
(a) Demonstrate CO2 emission performance jointly for all
affected entities in all states participating in the multi-state plan,
as follows:
(1) For states demonstrating performance based on the
CO2 emission rate, the level of performance identified in
the multi-state plan pursuant to Sec. 60.5740(a)(3) will be a weighted
(by net energy output) average lb CO2/MWh emission rate to
be achieved by all affected EGUs in the multi-state area during the
plan performance period; or
(2) For states demonstrating performance based on mass
CO2 emissions, the level of performance identified in the
multi-state plan pursuant to 60.5740(a)(3) will be total CO2
emissions by all affected EGUs in the multi-state area during the plan
performance period.
(b) Assign among states, according to a formula in the multi-state
plan, avoided CO2 emissions resulting from emission
standards contained in the plan, from affected entities in states
participating in the multi-state plan.
Sec. 60.5750 Can I include existing requirements, programs, and
measures in my state plan?
(a) Yes, you may include existing requirements, programs and
measures in your plan according to paragraphs (b) through (d) of this
section.
(b) Existing state programs, requirements, and measures, may
qualify for use in demonstrating that a state plan achieves the
required level of emission performance specified in a plan, according
to Sec. 60.5740(a)(3).
(c) Existing state programs, requirements, and measures, may
qualify for use in projecting that a state plan will achieve the
required level of emission performance specified in a plan, according
to Sec. 60.5740(a)(4).
(d) Emission impacts of existing programs, requirements, and
measures that occur during a plan performance period may be recognized
in meeting or projecting CO2 emission performance by
affected EGUs according to Sec. 60.5740(a)(3) and (4), as long as they
meet the following requirements:
(1) Actions taken pursuant to an existing state program,
requirement, or measure, such as compliance with a regulatory
obligation or initiation of an action related to a program or measure,
must occur after June 18, 2014; and
(2) The existing state program, requirement, or measure, and any
related actions taken pursuant to such program, requirement, or
measure, meet the applicable requirements pursuant to Sec. 60.5740(a)
and Sec. 60.5780.
Sec. 60.5755 What are the timing requirements for submitting my state
plan?
(a) You must submit your state plan with the information in Sec.
60.5740 by June 30, 2016 unless you are submitting a request for
extension according to paragraphs (b) or (c) of this section.
(b) For a state seeking a one year extension for a complete plan
submittal you must include the information in Sec. 60.5760(a) in a
submittal by June 30, 2016 to receive an extension to submit your
complete state plan by June 30, 2017.
(c) For states in a multi-state plan seeking a two year extension
for a complete plan submittal you must include the information in Sec.
60.5760(a) in a submittal by June 30, 2016 to receive an extension to
submit your complete multi-state plan by June 30, 2018.
Sec. 60.5760 What must I include in an initial submittal in lieu of a
complete state plan?
(a) You must include the following required elements in an initial
submittal in lieu of a complete state plan:
(1) A description of the plan approach and progress made to date in
developing each of the plan elements in Sec. 60.5740;
(2) An initial projection of the level of emission performance that
will be achieved under the complete plan;
(3) A commitment by the state to maintain existing state programs
and
[[Page 34953]]
measures that limit or avoid CO2 emissions from affected
entities (e.g., renewable energy standards, unit-specific limits on
operation or fuel utilization), which must at a minimum apply during
the interim period prior to state submission and EPA approval of a
complete plan, and must continue to apply in lieu of a complete plan if
one is ultimately not submitted and approved;
(4) Justification of why additional time is needed to submit a
complete plan;
(5) A comprehensive roadmap for completing the plan, including
process, analytical methods and schedule (including milestones)
specifying when all necessary plan components will be complete (e.g.,
projection of emission performance; implementing legislation,
regulations and agreements; necessary approvals);
(6) Identification of existing and future programs, requirements,
and measures the state intends to include in the plan;
(7) If a multi-state plan is being developed, an executed
agreement(s) with other states (e.g., MOU) participating in the
development of the multistate plan; and
(8) A commitment to submit a complete plan by June 30, 2017, for a
single-state plan, or June 30, 2018, for a multi-state plan, and
actions the state will take to show progress in addressing incomplete
plan components prior to submittal of the complete plan.
(9) A description of all steps the state has already taken in
furtherance of actions needed to finalize a complete plan.
(10) Evidence of an opportunity for public comment and a response
to any significant comments received on issues relating to the
approvability of the initial plan.
(b) You must submit either a complete state plan or an initial
submittal by June 30, 2016. Where an initial submittal is submitted in
lieu of a complete state plan the due date of a complete state plan
will be June 30, 2017, for a single-state plan, or June 30, 2018, for a
multi-state plan unless a state is notified within 60 days of the EPA
receiving the initial submittal in paragraph (a) of this section that
the EPA finds the initial submittal does not meet the requirements
listed in paragraph (a) of this section.
Sec. 60.5765 What are the state rate-based CO2 emissions
performance goals?
(a) The annual average state rate-based CO2 emission
performance goals for the interim performance periods of 2020 through
2029, and the final 2030 and thereafter period are respectively listed
in Table 1 of this Subpart. The state rate-based CO2
emission performance goal may be converted to a mass-based emission
performance goal according to Sec. 60.5770.
(b)[Reserved]
Sec. 60.5770 What is the procedure for converting my state rate-based
CO2 emission performance goal to a mass-based CO2
emissions performance goal?
(a) If the plan adopts a mass-based goal according to Sec.
60.5740(a)(3), the plan must identify the mass-based goal, in tons of
CO2 emitted by affected EGUs over the plan performance
period, and include a description of the analytic process, tools,
methods, and assumptions used to convert from the rate-based goal for
the state identified in Table 1 of this Subpart to an equivalent mass-
based goal. The conversion process must include following requirements:
(1) The process, tools, methods, and assumptions used in the
conversion of the rate-based goal must be included in your state plan
according to Sec. 60.5740(a)(11).
(2) The material supporting the conversion of the rate-based goal,
including results, data, and descriptions, must be include in a state
plan according to Sec. 60.5740(a)(11).
(3) The conversion must represent the tons of CO2
emissions that are projected to be emitted by affected EGUs, in the
absence of emission standards contained in the plan, if the affected
EGUs were to perform at an average lb CO2/MWh rate equal to
the rate-based goal for the state identified in Table 1 of this
Subpart.
(b) [Reserved]
Sec. 60.5775 What schedules, performance periods, and compliance
periods must I include in my state plan?
(a) Your state plan must include a schedule of compliance for each
affected entity regulated under the plan.
(b) Your state plan must include compliance periods, as defined in
section Sec. 60.5820, for each affected entity regulated under the
plan.
(c) For the interim performance period of 2020-2029 your state must
meet the requirements in paragraphs (c)(1) and (2) of this section.
(1) Your state plan must include increments of emissions
performance (either rate based or mass based with respect to the
interim level of performance set in the state plan) within the interim
performance period for every 2-rolling calendar years starting January
1, 2020 and ending in 2028 (i.e. 2020-2021, 2021-2022, 2022-2023,
etc.), unless other periods that ensure regular progress in the interim
period are approved by the Administrator.
(2) At the end of 2029 your state must meet the interim emissions
performance level specified in Sec. 60.5740(a)(3) as averaged over the
plan performance period 2020-2029.
(d) During the final performance period, 2030 and thereafter, your
state must meet the final emission performance level specified in Sec.
60.5740(a)(3) on a 3-calendar year rolling average starting January 1,
2030 (i.e., 2030-2032, 2031-2033, 2032-2034, etc.).
(e) You must include the provisions of your state plan which
demonstrate progress and compliance with the requirements in this Sec.
60.5775 and Sec. 60.5740 in your state's annual report required in
Sec. 60.5815.
Sec. 60.5780 What emission standards and enforcing measures must I
include in my plan?
(a) Your state plan shall include emission standard(s) that are
quantifiable, verifiable, non-duplicative, permanent, and enforceable
with respect to each affected entity. The plan shall include the
methods by which each emission standard meets each of the following
requirements in paragraphs (b) through (f) of this section.
(b) An emission standard is quantifiable with respect to an
affected entity if it can be reliably measured, in a manner that can be
replicated.
(c) An emission standard is verifiable with respect to an affected
entity if adequate monitoring, recordkeeping and reporting requirements
are in place to enable the state and the Administrator to independently
evaluate, measure, and verify compliance with the emission standard.
(d) An emission standard is non-duplicative with respect to an
affected entity if it is not already incorporated as an emission
standard in another state plan unless incorporated in multi-state plan.
(e) An emission standard is permanent with respect to an affected
entity if the emission standard must be met for each compliance period,
or unless it is replaced by another emission standard in an approved
plan revision, or the state demonstrates in an approved plan revision
that the emission reductions from the emission standard are no longer
necessary for the state to meet its state level of performance.
(f) An emission standard is enforceable against an affected entity
if:
(1) A technically accurate limitation or requirement and the time
period for
[[Page 34954]]
the limitation or requirement is specified;
(2) Compliance requirements are clearly defined;
(3) The affected entities responsible for compliance and liable for
violations can be identified;
(4) Each compliance activity or measure is enforceable as a
practical matter; and
(5) The Administrator and the state maintain the ability to enforce
violations and secure appropriate corrective actions pursuant to
sections 113(a) through (h) of the Act.
Sec. 60.5785 What is the procedure for revising my state plan?
State plans can only be revised with approval by the Administrator.
If one (or more) of the elements of the state plan set in Sec. 60.5740
require revision with respect to reaching the emission performance goal
set in Sec. 60.5765 a request may be submitted to the Administrator
indicating the proposed corrections to the state plan to ensure the
emission performance goal is met.
Applicability of State Plans to Affected EGUs
Sec. 60.5790 Does this subpart directly affect EGU owners and
operators in my state?
(a) This subpart does not directly affect EGU owners and operators
in your state. However, EGU owners and operators must comply with the
state plan that a state develops to implement the emission guidelines
contained in this subpart.
(b) If a state does not submit an approvable plan or initial
submittal to implement and enforce the emission guidelines contained in
this subpart by June 30, 2016, the EPA will implement and enforce a
Federal plan, as provided in Sec. 60.5740, to ensure that each
affected EGU within the state that commenced construction on or before
January 8, 2014 reaches compliance with all the provisions of this
subpart.
Sec. 60.5795 What affected EGUs must I address in my state plan?
(a) The EGUs that must be addressed by your state plan are any
affected steam generating unit, IGCC, or stationary combustion turbine
that commences construction on or before January 8, 2014.
(b) An affected EGU is a steam generating unit, integrated
gasification combined cycle (IGCC), or stationary combustion turbine
that meets the relevant applicability conditions specified in paragraph
(b)(1) or (2) of this section.
(1) A steam generating unit or IGCC that has a base load rating
greater than 73 MW (250 MMBtu/h) heat input of fossil fuel (either
alone or in combination with any other fuel) and was constructed for
the purpose of supplying one-third or more of its potential electric
output and more than 219,000 MWh net-electric output to a utility
distribution system on an annual basis.
(2) A stationary combustion turbine that has a base load rating
greater than 73 MW (250 MMBtu/h), was constructed for the purpose of
supplying, and supplies, one-third or more of its potential electric
output and more than 219,000 MWh net-electrical output to a utility
distribution system on a 3-year rolling average basis, combusts fossil
fuel for more than 10.0 percent of the heat input during a 3-year
rolling average basis and combusts over 90% natural gas on a heat input
basis on a 3-year rolling average basis.
Sec. 60.5800 What affected EGUs are exempt from my state plan?
Affected EGUs that are exempt from your state plan include: those
that are subject to subpart TTTT as a result of commencing construction
or reconstruction after the subpart TTTT applicability date; and those
subject to subpart TTTT as a result of commencing modification or
reconstruction prior becoming subject to an applicable state plan.
Sec. 60.5805 What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my state plan for affected EGUs?
(a) A state plan must include monitoring that is no less stringent
that what is described in (a)(1) through (6) of this section.
(1) If an affected EGU is required to meet a rate based emission
standard they must prepare a monitoring plan in accordance with the
applicable provisions in Sec. 75.53(g) and (h) of this chapter.
(2) An affected EGU must measure the hourly CO2 mass
emissions from each affected unit using the procedures in paragraphs
(a)(2)(i) through (v) of this section, except as provided in paragraph
(a)(3) of this section.
(i) An affected EGU must install, certify, operate, maintain, and
calibrate a CO2 continuous emissions monitoring system
(CEMS) to directly measure and record CO2 concentrations in
the affected EGU exhaust gases emitted to the atmosphere and an exhaust
gas flow rate monitoring system according to Sec. 75.10(a)(3)(i) of
this chapter. If an affected EGU measures CO2 concentration
on a dry basis, they must also install, certify, operate, maintain, and
calibrate a continuous moisture monitoring system, according to Sec.
75.11(b) of this chapter.
(ii) For each monitoring system an affected EGU uses to determine
the CO2 mass emissions, they must meet the applicable
certification and quality assurance procedures in Sec. 75.20 of this
chapter and Appendices B and D to part 75 of this chapter.
(iii) An affected EGU must use a laser device to measure the
dimensions of each exhaust gas stack or duct at the flow monitor and
the reference method sampling locations prior to the initial setup
(characterization) of the flow monitor. For circular stacks, an
affected EGU must measure the diameter at three or more distinct
locations and average the results. For rectangular stacks or ducts, an
affected EGU must measure each dimension (i.e., depth and width) at
three or more distinct locations and average the results. If the flow
rate monitor or reference method sampling site is relocated, an
affected EGU must repeat these measurements at the new location.
(iv) An affected EGU must use only unadjusted exhaust gas
volumetric flow rates to determine the hourly CO2 mass
emissions from the affected facility; an affected EGU must not apply
the bias adjustment factors described in section 7.6.5 of Appendix A to
part 75 of this chapter to the exhaust gas flow rate data.
(v) If an affected EGU chooses to use Method 2 in Appendix A-1 to
this part to perform the required relative accuracy test audits (RATAs)
of the part 75 flow rate monitoring system, they must use a calibrated
Type-S pitot tube or pitot tube assembly. An affected EGU must not use
the default Type-S pitot tube coefficient.
(3) If an affected EGU exclusively combusts liquid fuel and/or
gaseous fuel as an alternative to complying with paragraph (b) of this
section, they may determine the hourly CO2 mass emissions by
using Equation G-4 in Appendix G to part 75 of this chapter according
to the requirements in paragraphs (a)(3)(i) and (ii) of this section.
(i) An affected EGU must implement the applicable procedures in
appendix D to part 75 of this chapter to determine hourly unit heat
input rates (MMBtu/h), based on hourly measurements of fuel flow rate
and periodic determinations of the gross calorific value (GCV) of each
fuel combusted.
(ii) An affected EGU may determine site-specific carbon-based F-
factors (Fc) using Equation F-7b in section 3.3.6 of
appendix F to part 75 of this chapter, and may use these Fc
values in the
[[Page 34955]]
emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.
(4) An affected EGU must install, calibrate, maintain, and operate
a sufficient number of watt meters to continuously measure and record
on an hourly basis net electric output. Measurements must be performed
using 0.2 accuracy class electricity metering instrumentation and
calibration procedures as specified under ANSI Standards No. C12.20.
Further, an affected EGU that is a combined heat and power facility
must install, calibrate, maintain and operate equipment to continuously
measure and record on an hourly basis useful thermal output and, if
applicable, mechanical output, which are used with net electric output
to determine net energy output.
(5) In accordance with Sec. 60.13(g), if two or more affected EGUs
that implement the continuous emissions monitoring provisions in
paragraph (a)(2) of this section share a common exhaust gas stack and
are subject to the same emissions standard, they may monitor the hourly
CO2 mass emissions at the common stack in lieu of monitoring
each EGU separately. If an affected EGU chooses this option, the hourly
net electric output for the common stack must be the sum of the hourly
net electric output of the individual affected facility and you must
express the operating time as ``stack operating hours'' (as defined in
Sec. 72.2 of this chapter).
(6) In accordance with Sec. 60.13(g), if the exhaust gases from an
affected EGU that implements the continuous emissions monitoring
provisions in paragraph (a)(2) of this section are emitted to the
atmosphere through multiple stacks (or if the exhaust gases are routed
to a common stack through multiple ducts and you elect to monitor in
the ducts), they must monitor the hourly CO2 mass emissions
and the ``stack operating time'' (as defined in Sec. 72.2 of this
chapter) at each stack or duct separately. In this case, an affected
EGU must determine compliance with an applicable emissions standard by
summing the CO2 mass emissions measured at the individual
stacks or ducts and dividing by the net energy output for the affected
EGU.
(b) An affected EGU must maintain records for at least 10 years
following the date of each occurrence, measurement, maintenance,
corrective action, report, or record.
(1) An affected EGU must maintain each record on site for at least
2 years after the date of each occurrence, measurement, maintenance,
corrective action, report, or record, according to Sec. 60.7. An
affected EGU may maintain the records off site and electronically for
the remaining year(s).
(c) An affected EGU must include in a report required by the state
plan covering each compliance period all hourly CO2
emissions and all hourly net electric output and all hourly net energy
output measurements for a CHP facility calculated from data monitored
according to paragraph (a) of this section.
Recordkeeping and Reporting Requirements
Sec. 60.5810 What are my state recordkeeping requirements?
(a) States must keep records of all plan components, plan
requirements, supporting documentation, and the status of meeting the
plan requirements defined in the state plan on an annual basis during
the interim plan performance period from 2020-2029. After 2029 states
must keep records of all information that is used to support any
continued effort to meet the final emissions performance goal.
(b) States must keep records of all data submitted by each affected
entity that is used to determine compliance with each affected entity's
emissions standard.
(c) If a state has a requirement for hourly CO2
emissions and net generation information to be used to calculate
compliance with an annual emissions standard for affected EGUs, any
information that is submitted to the EPA electronically pursuant to
requirements in Part 75 would meet the recordkeeping requirement of
this section and a state would not need to keep records of information
that would be in duplicate of paragraph (b) of this section.
(d) A state must keep records at minimum for 20 years.
Sec. 60.5815 What are my state reporting requirements?
(a) You must submit an annual report covering each calendar year no
later than July 1 of the following year, starting July 1 2021. The
annual report must include the following:
(1) The level of emissions performance achieved by all affected
entities and identification of whether affected entities are on
schedule to meet the applicable level of emissions performance for
affected entities during the plan performance period and compliance
periods, as specified in the plan.
(2) The level of emissions performance achieved by all affected
EGUs during the reporting period, and prior reporting periods,
expressed as average CO2 emissions rate or total mass
CO2 emissions, consistent with the plan approach, and
identification of whether affected EGUs are on schedule to meet the
applicable level of emissions performance for affected EGUs during the
plan performance period, as specified in the plan.
(3) A list of affected entities and their compliance status with
the applicable emissions standards specified in the state plan.
(4) A list of all affected EGUs and their reported CO2
emissions performance for each compliance period during the reporting
period, and prior reporting periods.
(5) All other required information, as specified in your state plan
according to Sec. 60.5740(a)(9).
(6) All information required by Sec. 60.5775(e).
(b) For each two-year period in Sec. 60.5775(c)(1), you must
compare the average CO2 emission performance achieved by
affected entities in the state versus the CO2 emission
performance projected in the state plan. If actual emission performance
is greater than 10 percent in excess to projected plan performance for
a two-year comparison period, you must explain the reasons for the
deviation and specify the corrective actions that will be taken to
ensure that the required interim and final levels of emission
performance in the plan will be met. The information required in this
paragraph must be included in the annual report required by paragraph
(a) of this section.
(c) You must include in your 2029 annual report (which is
subsequently due by July 1, 2030) the calculation of average emissions
over the 2020-2029 interim performance period used to determine
compliance with your interim emission performance level. The calculated
value must be in units consistent with your interim emission
performance level.
(d) You must include in each report, starting with the 2032 annual
report (which is subsequently due by July 1, 2033), a 3-calendar year
rolling average used to determine compliance with the final emission
performance level. The calculated value must be in units consistent
with your final emission performance level.
Definitions
Sec. 60.5820 What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subparts A (General
Provisions) and B of this part.
[[Page 34956]]
Affected electric generating unit or Affected EGU means a steam
generating unit, an IGCC facility, or a stationary combustion turbine
that meets the applicability conditions in section Sec. 60.5795.
Affected Entity shall mean any of the following: An affected EGU,
or another entity with obligations under this subpart for the purpose
of meeting the emissions performance goal requirements in these
emission guidelines.
Base load rating means the maximum amount of heat input (fuel) that
a steam generating unit can combust on a steady state basis, as
determined by the physical design and characteristics of the steam
generating unit at ISO conditions. For a stationary combustion turbine,
base load rating means 100 percent of the design heat input capacity of
the simple cycle portion of the stationary combustion turbine at ISO
conditions (heat input from duct burners is not included).
CO2 emissions performance goal means the rate-based CO2
emissions performance goal specified for a state in Table 1 of this
subpart, or a translated mass-based form of that goal.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec. 60.17),
coal refuse, and petroleum coke. Synthetic fuels derived from coal for
the purpose of creating useful heat, including but not limited to
solvent-refined coal, gasified coal (not meeting the definition of
natural gas), coal-oil mixtures, and coal-water mixtures are included
in this definition for the purposes of this subpart.
Combined cycle facility means an electric generating unit that uses
a stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
Combined heat and power facility or CHP facility, (also known as
``cogeneration'') means an electric generating unit that that use a
steam-generating unit or stationary combustion turbine to
simultaneously produce both electric (or mechanical) and useful thermal
output from the same primary energy source.
Compliance period means the period of time, set forth by a state in
its state plan, during which each affected entity must demonstrate
compliance with an applicable emissions standard, and shall be no
greater than a three year period for a mass-based plan, and shall be no
greater than a one year period for a rate-based plan.
Emission performance level in a state plan means the level of
emissions performance for affected entities specified in a state plan,
according to Sec. 60.5740.
Emission standard means in addition to the definition in Sec.
60.21, any requirement applicable to any affected entity other than an
affected source that has the effect of reducing utilization of one or
more affected sources, thereby avoiding emissions from such sources,
including, for example, renewable energy and demand-side energy
efficiency measures requirements.
Excess emissions means a specified averaging period over which the
CO2 emissions rate is higher than an applicable emissions
standard or an averaging period during which an affected EGU is not in
compliance with any other emission limitation specified in an emission
standard.
Existing state program, requirement, or measure means, in the
context of a state plan, a regulation, requirement, program, or measure
administered by a state, utility, or other entity that is currently
established. This may include a regulation or other legal requirement
that includes past, current, and future obligations, or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future, in accordance with established
plans. An existing state program, requirement, or measure may have
past, current, and future impacts on EGU CO2 emissions.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
Integrated gasification combined cycle facility or IGCC facility
means a combined cycle facility that is designed to burn fuels
containing 50 percent (by heat input) or more solid-derived fuel not
meeting the definition of natural gas plus any integrated equipment
that provides electricity or useful thermal output to either the
affected facility or auxiliary equipment. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
Liquid fuel means any fuel that is present as a liquid at ISO
conditions and includes, but is not limited to, distillate oil and
residual oil.
Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: Landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
Net-electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility, plus 75 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application).
(2) For combined heat and power facilities where at least 20.0
percent of
[[Page 34957]]
the total gross energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross energy output consists of
useful thermal output on a rolling 3 year basis, the net electric or
mechanical output from the affected facility divided by 0.95, plus 75
percent of the useful thermal output measured relative to SATP
conditions that is not used to generate additional electric or
mechanical output or to enhance the performance of the unit (e.g.,
steam delivered to an industrial process for a heating application).
Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate and residual oil.
Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25[deg] C, 77 [deg]F)) and 100.0 kilopascals (14.504
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is
50 Btu/lb.
Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emissions control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. If a stationary
combustion turbine burns any solid fuel directly it is considered a
steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
Useful thermal output means the thermal energy made available for
use in any industrial or commercial process, or used in any heating or
cooling application, i.e., total thermal energy made available for
processes and applications other than electric generation, mechanical
output at the affected facility, or to directly enhance the performance
of the affected facility (e.g., economizer output is not useful thermal
output, but thermal energy used to reduce fuel moisture is considered
useful thermal output). Useful thermal output for affected facilities
with no condensate return (or other thermal energy input to the
affected facility) or where measuring the energy in the condensate (or
other thermal energy input to the affected facility) would not
meaningfully impact the emission rate calculation is measured against
the energy in the thermal output at SATP conditions. Affected
facilities with meaningful energy in the condensate return (or other
thermal energy input to the affected facility) must measure the energy
in the condensate and subtract that energy relative to SATP conditions
from the measured thermal output.
Table 1 to Subpart UUUU of Part 60--State Rate-Based CO2 Emission
Performance Goals
[Pounds of CO2 per net MWh]
------------------------------------------------------------------------
State Interim goal Final goal
------------------------------------------------------------------------
Alabama............................. 1,147 1,059
Alaska.............................. 1,097 1,003
Arizona............................. 735 702
Arkansas............................ 968 910
California.......................... 556 537
Colorado............................ 1,159 1,108
Connecticut......................... 597 540
Delaware............................ 913 841
Florida............................. 794 740
Georgia............................. 891 834
Hawaii.............................. 1,378 1,306
Idaho............................... 244 228
Illinois............................ 1,366 1,271
Indiana............................. 1,607 1,531
Iowa................................ 1,341 1,301
Kansas.............................. 1,578 1,499
Kentucky............................ 1,844 1,763
Louisiana........................... 948 883
Maine............................... 393 378
Maryland............................ 1,347 1,187
Massachusetts....................... 655 576
Michigan............................ 1,227 1,161
Minnesota........................... 911 873
Mississippi......................... 732 692
Missouri............................ 1,621 1,544
Montana............................. 1,882 1,771
Nebraska............................ 1,596 1,479
Nevada.............................. 697 647
New Hampshire....................... 546 486
New Jersey.......................... 647 531
New Mexico.......................... 1,107 1,048
New York............................ 635 549
North Carolina...................... 1,077 992
North Dakota........................ 1,817 1,783
[[Page 34958]]
Ohio................................ 1,452 1,338
Oklahoma............................ 931 895
Oregon.............................. 407 372
Pennsylvania........................ 1,179 1,052
Rhode Island........................ 822 782
South Carolina...................... 840 772
South Dakota........................ 800 741
Tennessee........................... 1,254 1,163
Texas............................... 853 791
Utah................................ 1,378 1,322
Virginia............................ 884 810
Washington.......................... 264 215
West Virginia....................... 1,748 1,620
Wisconsin........................... 1,281 1,203
Wyoming............................. 1,808 1,714
------------------------------------------------------------------------
[FR Doc. 2014-13726 Filed 6-17-14; 8:45 am]
BILLING CODE 6560-50-P